System and method for protecting components in a gas turbine engine with exhaust gas recirculation

ABSTRACT

A system includes a gas turbine engine that includes a combustor section having one or more combustors configured to generate combustion products, a turbine section having one or more turbine stages between an upstream end and a downstream end, an exhaust section disposed downstream from the downstream end of the turbine section, and a fluid supply system coupled to the exhaust section. The one or more turbine stages are driven by the combustion products. The exhaust section has an exhaust passage configured to receive the combustion products as an exhaust gas. The fluid supply system is configured to route a cooling gas to the exhaust section. The cooling gas has a temperature lower than the exhaust gas. The cooling gas includes an extracted exhaust gas, a gas separated from the extracted exhaust gas, carbon dioxide, carbon monoxide, nitrogen oxides, or a combination thereof.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to and benefit of U.S. ProvisionalPatent Application No. 61/747,206, entitled “SYSTEM AND METHOD FORPROTECTING COMPONENTS IN A GAS TURBINE ENGINE WITH EXHAUST GASRECIRCULATION,” filed on Dec. 28, 2012, U.S. Provisional PatentApplication No. 61/722,118, entitled “SYSTEM AND METHOD FOR DIFFUSIONCOMBUSTION IN A STOICHIOMETRIC EXHAUST GAS RECIRCULATION GAS TURBINESYSTEM,” filed on Nov. 2, 2012, U.S. Provisional Patent Application No.61/722,115, entitled “SYSTEM AND METHOD FOR DIFFUSION COMBUSTION WITHFUEL-DILUENT MIXING IN A STOICHIOMETRIC EXHAUST GAS RECIRCULATION GASTURBINE SYSTEM,” filed on Nov. 2, 2012, U.S. Provisional PatentApplication No. 61/722,114, entitled “SYSTEM AND METHOD FOR DIFFUSIONCOMBUSTION WITH OXIDANT-DILUENT MIXING IN A STOICHIOMETRIC EXHAUST GASRECIRCULATION GAS TURBINE SYSTEM,” filed on Nov. 2, 2012, and U.S.Provisional Patent Application No. 61/722,111, entitled “SYSTEM ANDMETHOD FOR LOAD CONTROL WITH DIFFUSION COMBUSTION IN A STOICHIOMETRICEXHAUST GAS RECIRCULATION GAS TURBINE SYSTEM,” filed on Nov. 2, 2012,all of which are herein incorporated by reference in their entirety forall purposes.

BACKGROUND OF THE INVENTION

The subject matter disclosed herein relates to gas turbine engines, andmore specifically, to systems and methods for protecting components ingas turbine engines.

Gas turbine engines are used in a wide variety of applications, such aspower generation, aircraft, and various machinery. Gas turbine enginesgenerally combust a fuel with an oxidant (e.g., air) in a combustorsection to generate hot combustion products, which then drive one ormore turbine stages of a turbine section. In turn, the turbine sectiondrives one or more compressor stages of a compressor section, therebycompressing oxidant for intake into the combustor section along with thefuel. Again, the fuel and oxidant mix in the combustor section, and thencombust to produce the hot combustion products. Unfortunately, certaincomponents of the combustor section and an exhaust section are exposedto high temperatures, which can result in thermal expansion, stress,and/or wear on the components. The exhaust gas can also leak intocertain cavities of the combustor section and/or the exhaust section,where the components may have a lower resistance to the high temperatureexhaust gas. Furthermore, gas turbine engines typically consume a vastamount of air as the oxidant, and output a considerable amount ofexhaust gas into the atmosphere. In other words, the exhaust gas istypically wasted as a byproduct of the gas turbine operation.

BRIEF DESCRIPTION OF THE INVENTION

Certain embodiments commensurate in scope with the originally claimedinvention are summarized below. These embodiments are not intended tolimit the scope of the claimed invention, but rather these embodimentsare intended only to provide a brief summary of possible forms of theinvention. Indeed, the invention may encompass a variety of forms thatmay be similar to or different from the embodiments set forth below.

In a first embodiment, a system includes a gas turbine engine thatincludes a combustor section having one or more combustors configured togenerate combustion products and a turbine section having one or moreturbine stages between an upstream end and a downstream end. The one ormore turbine stages are driven by the combustion products. The gasturbine engine also includes an exhaust section disposed downstream fromthe downstream end of the turbine section. The exhaust section has anexhaust passage configured to receive the combustion products as anexhaust gas. The gas turbine engine also includes a fluid supply systemcoupled to the exhaust section. The fluid supply system is configured toroute a cooling gas to the exhaust section. The cooling gas has atemperature lower than the exhaust gas. The cooling gas includes anextracted exhaust gas, a gas separated from the extracted exhaust gas,carbon dioxide, carbon monoxide, nitrogen oxides, or a combinationthereof.

In a second embodiment, a system includes a turbine exhaust sectionconfigured to mount downstream from a turbine section of a gas turbineengine. The turbine exhaust section includes an exhaust passageconfigured to receive exhaust gas from the turbine section, and acooling gas passage extending through a structure of the turbine exhaustsection. The system also includes a fluid supply system coupled to theexhaust section. The fluid supply system is configured to route acooling gas to the cooling gas passage in the exhaust section. Thecooling gas has a temperature lower than the exhaust gas. The coolinggas includes an extracted exhaust gas, a gas separated from theextracted exhaust gas, carbon dioxide, carbon monoxide, nitrogen oxides,or a combination thereof.

In a third embodiment, a system includes a turbine exhaust sectionconfigured to mount downstream from a turbine section of a gas turbineengine. The turbine exhaust section includes an exhaust passageconfigured to receive exhaust gas from the turbine section, and acooling gas passage extending through a structure of the turbine exhaustsection to route a cooling gas to the turbine exhaust section. Thecooling gas has a temperature lower than the exhaust gas. The coolinggas includes an extracted exhaust gas, a gas separated from theextracted exhaust gas, carbon dioxide, carbon monoxide, nitrogen oxides,or a combination thereof.

In a fourth embodiment, a method includes combusting a fuel with anoxidant and an exhaust gas in a combustion portion of a turbinecombustor to generate combustion products, driving a turbine with thecombustion products from the turbine combustor, expanding and coolingthe combustion products from the turbine through an exhaust passage inan exhaust section, and routing a cooling gas from a fluid supply systemto the exhaust section. The cooling gas includes an extracted exhaustgas, a gas separated from the extracted exhaust gas, carbon dioxide,carbon monoxide, nitrogen oxides, or a combination thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentinvention will become better understood when the following detaileddescription is read with reference to the accompanying drawings in whichlike characters represent like parts throughout the drawings, wherein:

FIG. 1 is a diagram of an embodiment of a system having a turbine-basedservice system coupled to a hydrocarbon production system;

FIG. 2 is a diagram of an embodiment of the system of FIG. 1, furtherillustrating a control system and a combined cycle system;

FIG. 3 is a diagram of an embodiment of the system of FIGS. 1 and 2,further illustrating details of a gas turbine engine, exhaust gas supplysystem, and exhaust gas processing system;

FIG. 4 is a flow chart of an embodiment of a process for operating thesystem of FIGS. 1-3;

FIG. 5 is a diagram of a fluid supply system for a gas turbine engine;

FIG. 6 is a diagram of an embodiment of a fluid supply system coupled toa gas turbine engine;

FIG. 7 is a cross-sectional view of a portion of a gas turbine enginecoupled to a fluid supply system; and

FIG. 8 is a cross-sectional view of a portion of an exhaust section of agas turbine engine coupled to a fluid supply system.

DETAILED DESCRIPTION

One or more specific embodiments of the present invention will bedescribed below. In an effort to provide a concise description of theseembodiments, all features of an actual implementation may not bedescribed in the specification. It should be appreciated that in thedevelopment of any such actual implementation, as in any engineering ordesign project, numerous implementation-specific decisions must be madeto achieve the developers' specific goals, such as compliance withsystem-related and business-related constraints, which may vary from oneimplementation to another. Moreover, it should be appreciated that sucha development effort might be complex and time consuming, but wouldnevertheless be a routine undertaking of design, fabrication, andmanufacture for those of ordinary skill having the benefit of thisdisclosure.

When introducing elements of various embodiments of the presentinvention, the articles “a,” “an,” “the,” and “said” are intended tomean that there are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements.

As discussed in detail below, the disclosed embodiments relate generallyto gas turbine systems with exhaust gas recirculation (EGR), andparticularly stoichiometric operation of the gas turbine systems usingEGR. For example, the gas turbine systems may be configured torecirculate the exhaust gas along an exhaust recirculation path,stoichiometrically combust fuel and oxidant along with at least some ofthe recirculated exhaust gas, and capture the exhaust gas for use invarious target systems. The recirculation of the exhaust gas along withstoichiometric combustion may help to increase the concentration levelof carbon dioxide (CO₂) in the exhaust gas, which can then be posttreated to separate and purify the CO₂ and nitrogen (N₂) for use invarious target systems. The gas turbine systems also may employ variousexhaust gas processing (e.g., heat recovery, catalyst reactions, etc.)along the exhaust recirculation path, thereby increasing theconcentration level of CO₂, reducing concentration levels of otheremissions (e.g., carbon monoxide, nitrogen oxides, and unburnthydrocarbons), and increasing energy recovery (e.g., with heat recoveryunits). Furthermore, the gas turbine engines may be configured tocombust the fuel and oxidant with one or more diffusion flames (e.g.,using diffusion fuel nozzles), premix flames (e.g., using premix fuelnozzles), or any combination thereof. In certain embodiments, thediffusion flames may help to maintain stability and operation withincertain limits for stoichiometric combustion, which in turn helps toincrease production of CO₂. For example, a gas turbine system operatingwith diffusion flames may enable a greater quantity of EGR, as comparedto a gas turbine system operating with premix flames. In turn, theincreased quantity of EGR helps to increase CO₂ production. Possibletarget systems include pipelines, storage tanks, carbon sequestrationsystems, and hydrocarbon production systems, such as enhanced oilrecovery (EOR) systems.

The disclosed embodiments provide systems and methods for protectingcomponents (e.g., via a protective gas flow) of gas turbine engines withEGR. The gas turbine engine may include a turbine section having one ormore turbine stages between an upstream end and a downstream end. Thegas turbine engine may also include an exhaust section disposeddownstream from the downstream end of the turbine section. Further, thegas turbine engine may include a fluid supply system (e.g., a protectiveor inert gas supply) coupled to the exhaust section. The fluid supplysystem may route a protective gas (e.g., an inert gas) to the exhaustsection of the gas turbine engine. For example, the protective gas maybe substantially or entirely free of oxygen, air, or any combinationthereof, and the protective gas also may be substantially or entirelyfree of fuel or unburnt hydrocarbons. Accordingly, the protective gasmay be described as an oxygen-free or substantially oxygen-freeprotective gas, and also a fuel-free or substantially fuel-freeprotective gas. The protective gas may include an inert gas, which maybe a noble gas or substantially non-reactive gas. Although a variety ofprotective gases may be used in the disclosed embodiments, the followingdiscussion focuses on inert gases as nonlimiting examples. Examples ofthe inert gas routed by the fluid supply system include, but are notlimited to, nitrogen, carbon dioxide, argon, exhaust gas, or anycombination thereof. The inert gas may be used for cooling, purging,fluidly sealing, or diluting cavities in various structures andcomponents of the exhaust section. For example, the inert gas routed bythe fluid supply system may be used to cool an outer shroud cavity, aninner shroud cavity, a vane, a bearing cavity, or any combinationthereof The inert gas may be routed from the fluid supply system to oneor more of these structures or components via an inert gas passagecoupled to the fluid supply system.

As a temperature of the inert gas routed from the fluid supply systemmay be less than a temperature of the exhaust gas flowing through anexhaust passage of the exhaust section, the inert gas may help to coolthe structures and components of the exhaust section. Thus, the inertgas may help to extend the life of the components and structures of theexhaust section. After cooling the components and structures of theexhaust section, the inert gas may combine with the exhaust gas flowingthrough the exhaust passage of the exhaust section. In certainembodiments, the use of the inert gas for cooling in the exhaust sectionmay provide several advantages compared to other cooling fluids, such asair. For example, the exhaust gas from the gas turbine engine may beused in certain applications in which a low concentration of oxygen inthe exhaust gas is desired. Compared to air, the inert gas may includelittle to no oxygen. Thus, use of the inert gas for cooling of theexhaust section may introduce little to no oxygen to the exhaust gas. Inaddition, various oils and lubricants may be used in the exhaust sectionof the gas turbine engine. During cooling of the exhaust section, theinert gas may come in contact with one or more of the lubricants oroils. Compared to air, the inert gas may cause little to no degradationof the oils and/or lubricants. In other words, the inert gas isgenerally non-reactive with the oils and/or lubricants. Thus, use of theinert gas for cooling the exhaust section may extend the life of theoils and lubricants used in the exhaust section. Additionally oralternatively, less expensive oils and/or lubricants may be used in theexhaust section when using inert gas for cooling. Further, the inert gasmay be used to help purge and/or dilute any exhaust gas leakage into thecavities of the exhaust section. Additionally or alternatively, theinert gas may be used to pressurize the cavities to resist leakage ofexhaust gas into the cavities.

FIG. 1 is a diagram of an embodiment of a system 10 having anhydrocarbon production system 12 associated with a turbine-based servicesystem 14. As discussed in further detail below, various embodiments ofthe turbine-based service system 14 are configured to provide variousservices, such as electrical power, mechanical power, and fluids (e.g.,exhaust gas), to the hydrocarbon production system 12 to facilitate theproduction or retrieval of oil and/or gas. In the illustratedembodiment, the hydrocarbon production system 12 includes an oil/gasextraction system 16 and an enhanced oil recovery (EOR) system 18, whichare coupled to a subterranean reservoir 20 (e.g., an oil, gas, orhydrocarbon reservoir). The oil/gas extraction system 16 includes avariety of surface equipment 22, such as a Christmas tree or productiontree 24, coupled to an oil/gas well 26. Furthermore, the well 26 mayinclude one or more tubulars 28 extending through a drilled bore 30 inthe earth 32 to the subterranean reservoir 20. The tree 24 includes oneor more valves, chokes, isolation sleeves, blowout preventers, andvarious flow control devices, which regulate pressures and control flowsto and from the subterranean reservoir 20. While the tree 24 isgenerally used to control the flow of the production fluid (e.g., oil orgas) out of the subterranean reservoir 20, the EOR system 18 mayincrease the production of oil or gas by injecting one or more fluidsinto the subterranean reservoir 20.

Accordingly, the EOR system 18 may include a fluid injection system 34,which has one or more tubulars 36 extending through a bore 38 in theearth 32 to the subterranean reservoir 20. For example, the EOR system18 may route one or more fluids 40, such as gas, steam, water,chemicals, or any combination thereof, into the fluid injection system34. For example, as discussed in further detail below, the EOR system 18may be coupled to the turbine-based service system 14, such that thesystem 14 routes an exhaust gas 42 (e.g., substantially or entirely freeof oxygen) to the EOR system 18 for use as the injection fluid 40. Thefluid injection system 34 routes the fluid 40 (e.g., the exhaust gas 42)through the one or more tubulars 36 into the subterranean reservoir 20,as indicated by arrows 44. The injection fluid 40 enters thesubterranean reservoir 20 through the tubular 36 at an offset distance46 away from the tubular 28 of the oil/gas well 26. Accordingly, theinjection fluid 40 displaces the oil/gas 48 disposed in the subterraneanreservoir 20, and drives the oil/gas 48 up through the one or moretubulars 28 of the hydrocarbon production system 12, as indicated byarrows 50. As discussed in further detail below, the injection fluid 40may include the exhaust gas 42 originating from the turbine-basedservice system 14, which is able to generate the exhaust gas 42 on-siteas needed by the hydrocarbon production system 12. In other words, theturbine-based system 14 may simultaneously generate one or more services(e.g., electrical power, mechanical power, steam, water (e.g.,desalinated water), and exhaust gas (e.g., substantially free ofoxygen)) for use by the hydrocarbon production system 12, therebyreducing or eliminating the reliance on external sources of suchservices.

In the illustrated embodiment, the turbine-based service system 14includes a stoichiometric exhaust gas recirculation (SEGR) gas turbinesystem 52 and an exhaust gas (EG) processing system 54. The gas turbinesystem 52 may be configured to operate in a stoichiometric combustionmode of operation (e.g., a stoichiometric control mode) and anon-stoichiometric combustion mode of operation (e.g., anon-stoichiometric control mode), such as a fuel-lean control mode or afuel-rich control mode. In the stoichiometric control mode, thecombustion generally occurs in a substantially stoichiometric ratio of afuel and oxidant, thereby resulting in substantially stoichiometriccombustion. In particular, stoichiometric combustion generally involvesconsuming substantially all of the fuel and oxidant in the combustionreaction, such that the products of combustion are substantially orentirely free of unburnt fuel and oxidant. One measure of stoichiometriccombustion is the equivalence ratio, or phi (φ), which is the ratio ofthe actual fuel/oxidant ratio relative to the stoichiometricfuel/oxidant ratio. An equivalence ratio of greater than 1.0 results ina fuel-rich combustion of the fuel and oxidant, whereas an equivalenceratio of less than 1.0 results in a fuel-lean combustion of the fuel andoxidant. In contrast, an equivalence ratio of 1.0 results in combustionthat is neither fuel-rich nor fuel-lean, thereby substantially consumingall of the fuel and oxidant in the combustion reaction. In context ofthe disclosed embodiments, the term stoichiometric or substantiallystoichiometric may refer to an equivalence ratio of approximately 0.95to approximately 1.05. However, the disclosed embodiments may alsoinclude an equivalence ratio of 1.0 plus or minus 0.01, 0.02, 0.03,0.04, 0.05, or more. Again, the stoichiometric combustion of fuel andoxidant in the turbine-based service system 14 may result in products ofcombustion or exhaust gas (e.g., 42) with substantially no unburnt fuelor oxidant remaining. For example, the exhaust gas 42 may have less than1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburntfuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbonmonoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and otherproducts of incomplete combustion. By further example, the exhaust gas42 may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90,100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts permillion by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel orhydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbonmonoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and otherproducts of incomplete combustion. However, the disclosed embodimentsalso may produce other ranges of residual fuel, oxidant, and otheremissions levels in the exhaust gas 42. As used herein, the termsemissions, emissions levels, and emissions targets may refer toconcentration levels of certain products of combustion (e.g., NO_(X),CO, SO_(X), O₂, N₂, H₂, HCs, etc.), which may be present in recirculatedgas streams, vented gas streams (e.g., exhausted into the atmosphere),and gas streams used in various target systems (e.g., the hydrocarbonproduction system 12).

Although the SEGR gas turbine system 52 and the EG processing system 54may include a variety of components in different embodiments, theillustrated EG processing system 54 includes a heat recovery steamgenerator (HRSG) 56 and an exhaust gas recirculation (EGR) system 58,which receive and process an exhaust gas 60 originating from the SEGRgas turbine system 52. The HRSG 56 may include one or more heatexchangers, condensers, and various heat recovery equipment, whichcollectively function to transfer heat from the exhaust gas 60 to astream of water, thereby generating steam 62. The steam 62 may be usedin one or more steam turbines, the EOR system 18, or any other portionof the hydrocarbon production system 12. For example, the HRSG 56 maygenerate low pressure, medium pressure, and/or high pressure steam 62,which may be selectively applied to low, medium, and high pressure steamturbine stages, or different applications of the EOR system 18. Inaddition to the steam 62, a treated water 64, such as a desalinatedwater, may be generated by the HRSG 56, the EGR system 58, and/oranother portion of the EG processing system 54 or the SEGR gas turbinesystem 52. The treated water 64 (e.g., desalinated water) may beparticularly useful in areas with water shortages, such as inland ordesert regions. The treated water 64 may be generated, at least in part,due to the large volume of air driving combustion of fuel within theSEGR gas turbine system 52. While the on-site generation of steam 62 andwater 64 may be beneficial in many applications (including thehydrocarbon production system 12), the on-site generation of exhaust gas42, 60 may be particularly beneficial for the EOR system 18, due to itslow oxygen content, high pressure, and heat derived from the SEGR gasturbine system 52. Accordingly, the HRSG 56, the EGR system 58, and/oranother portion of the EG processing system 54 may output or recirculatean exhaust gas 66 into the SEGR gas turbine system 52, while alsorouting the exhaust gas 42 to the EOR system 18 for use with thehydrocarbon production system 12. Likewise, the exhaust gas 42 may beextracted directly from the SEGR gas turbine system 52 (i.e., withoutpassing through the EG processing system 54) for use in the EOR system18 of the hydrocarbon production system 12.

The exhaust gas recirculation is handled by the EGR system 58 of the EGprocessing system 54. For example, the EGR system 58 includes one ormore conduits, valves, blowers, exhaust gas treatment systems (e.g.,filters, particulate removal units, gas separation units, gaspurification units, heat exchangers, heat recovery units, moistureremoval units, catalyst units, chemical injection units, or anycombination thereof), and controls to recirculate the exhaust gas alongan exhaust gas circulation path from an output (e.g., discharged exhaustgas 60) to an input (e.g., intake exhaust gas 66) of the SEGR gasturbine system 52. In the illustrated embodiment, the SEGR gas turbinesystem 52 intakes the exhaust gas 66 into a compressor section havingone or more compressors, thereby compressing the exhaust gas 66 for usein a combustor section along with an intake of an oxidant 68 and one ormore fuels 70. The oxidant 68 may include ambient air, pure oxygen,oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, orany suitable oxidant that facilitates combustion of the fuel 70. Thefuel 70 may include one or more gas fuels, liquid fuels, or anycombination thereof. For example, the fuel 70 may include natural gas,liquefied natural gas (LNG), syngas, methane, ethane, propane, butane,naphtha, kerosene, diesel fuel, ethanol, methanol, biofuel, or anycombination thereof.

The SEGR gas turbine system 52 mixes and combusts the exhaust gas 66,the oxidant 68, and the fuel 70 in the combustor section, therebygenerating hot combustion gases or exhaust gas 60 to drive one or moreturbine stages in a turbine section. In certain embodiments, eachcombustor in the combustor section includes one or more premix fuelnozzles, one or more diffusion fuel nozzles, or any combination thereof.For example, each premix fuel nozzle may be configured to mix theoxidant 68 and the fuel 70 internally within the fuel nozzle and/orpartially upstream of the fuel nozzle, thereby injecting an oxidant-fuelmixture from the fuel nozzle into the combustion zone for a premixedcombustion (e.g., a premixed flame). By further example, each diffusionfuel nozzle may be configured to isolate the flows of oxidant 68 andfuel 70 within the fuel nozzle, thereby separately injecting the oxidant68 and the fuel 70 from the fuel nozzle into the combustion zone fordiffusion combustion (e.g., a diffusion flame). In particular, thediffusion combustion provided by the diffusion fuel nozzles delaysmixing of the oxidant 68 and the fuel 70 until the point of initialcombustion, i.e., the flame region. In embodiments employing thediffusion fuel nozzles, the diffusion flame may provide increased flamestability, because the diffusion flame generally forms at the point ofstoichiometry between the separate streams of oxidant 68 and fuel 70(i.e., as the oxidant 68 and fuel 70 are mixing). In certainembodiments, one or more diluents (e.g., the exhaust gas 60, steam,nitrogen, or another inert gas) may be pre-mixed with the oxidant 68,the fuel 70, or both, in either the diffusion fuel nozzle or the premixfuel nozzle. In addition, one or more diluents (e.g., the exhaust gas60, steam, nitrogen, or another inert gas) may be injected into thecombustor at or downstream from the point of combustion within eachcombustor. The use of these diluents may help temper the flame (e.g.,premix flame or diffusion flame), thereby helping to reduce NO_(X)emissions, such as nitrogen monoxide (NO) and nitrogen dioxide (NO₂).Regardless of the type of flame, the combustion produces hot combustiongases or exhaust gas 60 to drive one or more turbine stages. As eachturbine stage is driven by the exhaust gas 60, the SEGR gas turbinesystem 52 generates a mechanical power 72 and/or an electrical power 74(e.g., via an electrical generator). The system 52 also outputs theexhaust gas 60, and may further output water 64. Again, the water 64 maybe a treated water, such as a desalinated water, which may be useful ina variety of applications on-site or off-site.

Exhaust extraction is also provided by the SEGR gas turbine system 52using one or more extraction points 76. For example, the illustratedembodiment includes an exhaust gas (EG) supply system 78 having anexhaust gas (EG) extraction system 80 and an exhaust gas (EG) treatmentsystem 82, which receive exhaust gas 42 from the extraction points 76,treat the exhaust gas 42, and then supply or distribute the exhaust gas42 to various target systems. The target systems may include the EORsystem 18 and/or other systems, such as a pipeline 86, a storage tank88, or a carbon sequestration system 90. The EG extraction system 80 mayinclude one or more conduits, valves, controls, and flow separations,which facilitate isolation of the exhaust gas 42 from the oxidant 68,the fuel 70, and other contaminants, while also controlling thetemperature, pressure, and flow rate of the extracted exhaust gas 42.The EG treatment system 82 may include one or more heat exchangers(e.g., heat recovery units such as heat recovery steam generators,condensers, coolers, or heaters), catalyst systems (e.g., oxidationcatalyst systems), particulate and/or water removal systems (e.g., gasdehydration units, inertial separators, coalescing filters, waterimpermeable filters, and other filters), chemical injection systems,solvent based treatment systems (e.g., absorbers, flash tanks, etc.),carbon capture systems, gas separation systems, gas purificationsystems, and/or a solvent based treatment system, exhaust gascompressors, any combination thereof. These subsystems of the EGtreatment system 82 enable control of the temperature, pressure, flowrate, moisture content (e.g., amount of water removal), particulatecontent (e.g., amount of particulate removal), and gas composition(e.g., percentage of CO₂, N₂, etc.).

The extracted exhaust gas 42 is treated by one or more subsystems of theEG treatment system 82, depending on the target system. For example, theEG treatment system 82 may direct all or part of the exhaust gas 42through a carbon capture system, a gas separation system, a gaspurification system, and/or a solvent based treatment system, which iscontrolled to separate and purify a carbonaceous gas (e.g., carbondioxide) 92 and/or nitrogen (N₂) 94 for use in the various targetsystems. For example, embodiments of the EG treatment system 82 mayperform gas separation and purification to produce a plurality ofdifferent streams 95 of exhaust gas 42, such as a first stream 96, asecond stream 97, and a third stream 98. The first stream 96 may have afirst composition that is rich in carbon dioxide and/or lean in nitrogen(e.g., a CO₂ rich, N₂ lean stream). The second stream 97 may have asecond composition that has intermediate concentration levels of carbondioxide and/or nitrogen (e.g., intermediate concentration CO₂, N₂stream). The third stream 98 may have a third composition that is leanin carbon dioxide and/or rich in nitrogen (e.g., a CO₂ lean, N₂ richstream). Each stream 95 (e.g., 96, 97, and 98) may include a gasdehydration unit, a filter, a gas compressor, or any combinationthereof, to facilitate delivery of the stream 95 to a target system. Incertain embodiments, the CO₂ rich, N₂ lean stream 96 may have a CO₂purity or concentration level of greater than approximately 70, 75, 80,85, 90, 95, 96, 97, 98, or 99 percent by volume, and a N₂ purity orconcentration level of less than approximately 1, 2, 3, 4, 5, 10, 15,20, 25, or percent by volume. In contrast, the CO₂ lean, N₂ rich stream98 may have a CO₂ purity or concentration level of less thanapproximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or percent by volume, and aN₂ purity or concentration level of greater than approximately 70, 75,80, 85, 90, 95, 96, 97, 98, or 99 percent by volume. The intermediateconcentration CO₂, N₂ stream 97 may have a CO₂ purity or concentrationlevel and/or a N₂ purity or concentration level of between approximately30 to 70, 35 to 65, 40 to 60, or 45 to 55 percent by volume. Althoughthe foregoing ranges are merely non-limiting examples, the CO₂ rich, N₂lean stream 96 and the CO₂ lean, N₂ rich stream 98 may be particularlywell suited for use with the EOR system 18 and the other systems 84.However, any of these rich, lean, or intermediate concentration CO₂streams 95 may be used, alone or in various combinations, with the EORsystem 18 and the other systems 84. For example, the EOR system 18 andthe other systems 84 (e.g., the pipeline 86, storage tank 88, and thecarbon sequestration system 90) each may receive one or more CO₂ rich,N₂ lean streams 96, one or more CO₂ lean, N₂ rich streams 98, one ormore intermediate concentration CO₂, N₂ streams 97, and one or moreuntreated exhaust gas 42 streams (i.e., bypassing the EG treatmentsystem 82).

The EG extraction system 80 extracts the exhaust gas 42 at one or moreextraction points 76 along the compressor section, the combustorsection, and/or the turbine section, such that the exhaust gas 42 may beused in the EOR system 18 and other systems 84 at suitable temperaturesand pressures. The EG extraction system 80 and/or the EG treatmentsystem 82 also may circulate fluid flows (e.g., exhaust gas 42) to andfrom the EG processing system 54. For example, a portion of the exhaustgas 42 passing through the EG processing system 54 may be extracted bythe EG extraction system 80 for use in the EOR system 18 and the othersystems 84. In certain embodiments, the EG supply system 78 and the EGprocessing system 54 may be independent or integral with one another,and thus may use independent or common subsystems. For example, the EGtreatment system 82 may be used by both the EG supply system 78 and theEG processing system 54. Exhaust gas 42 extracted from the EG processingsystem 54 may undergo multiple stages of gas treatment, such as one ormore stages of gas treatment in the EG processing system 54 followed byone or more additional stages of gas treatment in the EG treatmentsystem 82.

At each extraction point 76, the extracted exhaust gas 42 may besubstantially free of oxidant 68 and fuel 70 (e.g., unburnt fuel orhydrocarbons) due to substantially stoichiometric combustion and/or gastreatment in the EG processing system 54. Furthermore, depending on thetarget system, the extracted exhaust gas 42 may undergo furthertreatment in the EG treatment system 82 of the EG supply system 78,thereby further reducing any residual oxidant 68, fuel 70, or otherundesirable products of combustion. For example, either before or aftertreatment in the EG treatment system 82, the extracted exhaust gas 42may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g.,oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides(e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)),hydrogen, and other products of incomplete combustion. By furtherexample, either before or after treatment in the EG treatment system 82,the extracted exhaust gas 42 may have less than approximately 10, 20,30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000,4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g.,oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides(e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)),hydrogen, and other products of incomplete combustion. Thus, the exhaustgas 42 is particularly well suited for use with the EOR system 18.

The EGR operation of the turbine system 52 specifically enables theexhaust extraction at a multitude of locations 76. For example, thecompressor section of the system 52 may be used to compress the exhaustgas 66 without any oxidant 68 (i.e., only compression of the exhaust gas66), such that a substantially oxygen-free exhaust gas 42 may beextracted from the compressor section and/or the combustor section priorto entry of the oxidant 68 and the fuel 70. The extraction points 76 maybe located at interstage ports between adjacent compressor stages, atports along the compressor discharge casing, at ports along eachcombustor in the combustor section, or any combination thereof. Incertain embodiments, the exhaust gas 66 may not mix with the oxidant 68and fuel 70 until it reaches the head end portion and/or fuel nozzles ofeach combustor in the combustor section. Furthermore, one or more flowseparators (e.g., walls, dividers, baffles, or the like) may be used toisolate the oxidant 68 and the fuel 70 from the extraction points 76.With these flow separators, the extraction points 76 may be disposeddirectly along a wall of each combustor in the combustor section.

Once the exhaust gas 66, oxidant 68, and fuel 70 flow through the headend portion (e.g., through fuel nozzles) into the combustion portion(e.g., combustion chamber) of each combustor, the SEGR gas turbinesystem 52 is controlled to provide a substantially stoichiometriccombustion of the exhaust gas 66, oxidant 68, and fuel 70. For example,the system 52 may maintain an equivalence ratio of approximately 0.95 toapproximately 1.05. As a result, the products of combustion of themixture of exhaust gas 66, oxidant 68, and fuel 70 in each combustor issubstantially free of oxygen and unburnt fuel. Thus, the products ofcombustion (or exhaust gas) may be extracted from the turbine section ofthe SEGR gas turbine system 52 for use as the exhaust gas 42 routed tothe EOR system 18. Along the turbine section, the extraction points 76may be located at any turbine stage, such as interstage ports betweenadjacent turbine stages. Thus, using any of the foregoing extractionpoints 76, the turbine-based service system 14 may generate, extract,and deliver the exhaust gas 42 to the hydrocarbon production system 12(e.g., the EOR system 18) for use in the production of oil/gas 48 fromthe subterranean reservoir 20.

FIG. 2 is a diagram of an embodiment of the system 10 of FIG. 1,illustrating a control system 100 coupled to the turbine-based servicesystem 14 and the hydrocarbon production system 12. In the illustratedembodiment, the turbine-based service system 14 includes a combinedcycle system 102, which includes the SEGR gas turbine system 52 as atopping cycle, a steam turbine 104 as a bottoming cycle, and the HRSG 56to recover heat from the exhaust gas 60 to generate the steam 62 fordriving the steam turbine 104. Again, the SEGR gas turbine system 52receives, mixes, and stoichiometrically combusts the exhaust gas 66, theoxidant 68, and the fuel 70 (e.g., premix and/or diffusion flames),thereby producing the exhaust gas 60, the mechanical power 72, theelectrical power 74, and/or the water 64. For example, the SEGR gasturbine system 52 may drive one or more loads or machinery 106, such asan electrical generator, an oxidant compressor (e.g., a main aircompressor), a gear box, a pump, equipment of the hydrocarbon productionsystem 12, or any combination thereof. In some embodiments, themachinery 106 may include other drives, such as electrical motors orsteam turbines (e.g., the steam turbine 104), in tandem with the SEGRgas turbine system 52. Accordingly, an output of the machinery 106driven by the SEGR gas turbines system 52 (and any additional drives)may include the mechanical power 72 and the electrical power 74. Themechanical power 72 and/or the electrical power 74 may be used on-sitefor powering the hydrocarbon production system 12, the electrical power74 may be distributed to the power grid, or any combination thereof. Theoutput of the machinery 106 also may include a compressed fluid, such asa compressed oxidant 68 (e.g., air or oxygen), for intake into thecombustion section of the SEGR gas turbine system 52. Each of theseoutputs (e.g., the exhaust gas 60, the mechanical power 72, theelectrical power 74, and/or the water 64) may be considered a service ofthe turbine-based service system 14.

The SEGR gas turbine system 52 produces the exhaust gas 42, 60, whichmay be substantially free of oxygen, and routes this exhaust gas 42, 60to the EG processing system 54 and/or the EG supply system 78. The EGsupply system 78 may treat and delivery the exhaust gas 42 (e.g.,streams 95) to the hydrocarbon production system 12 and/or the othersystems 84. As discussed above, the EG processing system 54 may includethe HRSG 56 and the EGR system 58. The HRSG 56 may include one or moreheat exchangers, condensers, and various heat recovery equipment, whichmay be used to recover or transfer heat from the exhaust gas 60 to water108 to generate the steam 62 for driving the steam turbine 104. Similarto the SEGR gas turbine system 52, the steam turbine 104 may drive oneor more loads or machinery 106, thereby generating the mechanical power72 and the electrical power 74. In the illustrated embodiment, the SEGRgas turbine system 52 and the steam turbine 104 are arranged in tandemto drive the same machinery 106. However, in other embodiments, the SEGRgas turbine system 52 and the steam turbine 104 may separately drivedifferent machinery 106 to independently generate mechanical power 72and/or electrical power 74. As the steam turbine 104 is driven by thesteam 62 from the HRSG 56, the steam 62 gradually decreases intemperature and pressure. Accordingly, the steam turbine 104recirculates the used steam 62 and/or water 108 back into the HRSG 56for additional steam generation via heat recovery from the exhaust gas60. In addition to steam generation, the HRSG 56, the EGR system 58,and/or another portion of the EG processing system 54 may produce thewater 64, the exhaust gas 42 for use with the hydrocarbon productionsystem 12, and the exhaust gas 66 for use as an input into the SEGR gasturbine system 52. For example, the water 64 may be a treated water 64,such as a desalinated water for use in other applications. Thedesalinated water may be particularly useful in regions of low wateravailability. Regarding the exhaust gas 60, embodiments of the EGprocessing system 54 may be configured to recirculate the exhaust gas 60through the EGR system 58 with or without passing the exhaust gas 60through the HRSG 56.

In the illustrated embodiment, the SEGR gas turbine system 52 has anexhaust recirculation path 110, which extends from an exhaust outlet toan exhaust inlet of the system 52. Along the path 110, the exhaust gas60 passes through the EG processing system 54, which includes the HRSG56 and the EGR system 58 in the illustrated embodiment. The EGR system58 may include one or more conduits, valves, blowers, gas treatmentsystems (e.g., filters, particulate removal units, gas separation units,gas purification units, heat exchangers, heat recovery units such asheat recovery steam generators, moisture removal units, catalyst units,chemical injection units, or any combination thereof) in series and/orparallel arrangements along the path 110. In other words, the EGR system58 may include any flow control components, pressure control components,temperature control components, moisture control components, and gascomposition control components along the exhaust recirculation path 110between the exhaust outlet and the exhaust inlet of the system 52.Accordingly, in embodiments with the HRSG 56 along the path 110, theHRSG 56 may be considered a component of the EGR system 58. However, incertain embodiments, the HRSG 56 may be disposed along an exhaust pathindependent from the exhaust recirculation path 110. Regardless ofwhether the HRSG 56 is along a separate path or a common path with theEGR system 58, the HRSG 56 and the EGR system 58 intake the exhaust gas60 and output either the recirculated exhaust gas 66, the exhaust gas 42for use with the EG supply system 78 (e.g., for the hydrocarbonproduction system 12 and/or other systems 84), or another output ofexhaust gas. Again, the SEGR gas turbine system 52 intakes, mixes, andstoichiometrically combusts the exhaust gas 66, the oxidant 68, and thefuel 70 (e.g., premixed and/or diffusion flames) to produce asubstantially oxygen-free and fuel-free exhaust gas 60 for distributionto the EG processing system 54, the hydrocarbon production system 12, orother systems 84.

As noted above with reference to FIG. 1, the hydrocarbon productionsystem 12 may include a variety of equipment to facilitate the recoveryor production of oil/gas 48 from a subterranean reservoir 20 through anoil/gas well 26. For example, the hydrocarbon production system 12 mayinclude the EOR system 18 having the fluid injection system 34. In theillustrated embodiment, the fluid injection system 34 includes anexhaust gas injection EOR system 112 and a steam injection EOR system114. Although the fluid injection system 34 may receive fluids from avariety of sources, the illustrated embodiment may receive the exhaustgas 42 and the steam 62 from the turbine-based service system 14. Theexhaust gas 42 and/or the steam 62 produced by the turbine-based servicesystem 14 also may be routed to the hydrocarbon production system 12 foruse in other oil/gas systems 116.

The quantity, quality, and flow of the exhaust gas 42 and/or the steam62 may be controlled by the control system 100. The control system 100may be dedicated entirely to the turbine-based service system 14, or thecontrol system 100 may optionally also provide control (or at least somedata to facilitate control) for the hydrocarbon production system 12and/or other systems 84. In the illustrated embodiment, the controlsystem 100 includes a controller 118 having a processor 120, a memory122, a steam turbine control 124, a SEGR gas turbine system control 126,and a machinery control 128. The processor 120 may include a singleprocessor or two or more redundant processors, such as triple redundantprocessors for control of the turbine-based service system 14. Thememory 122 may include volatile and/or non-volatile memory. For example,the memory 122 may include one or more hard drives, flash memory,read-only memory, random access memory, or any combination thereof. Thecontrols 124, 126, and 128 may include software and/or hardwarecontrols. For example, the controls 124, 126, and 128 may includevarious instructions or code stored on the memory 122 and executable bythe processor 120. The control 124 is configured to control operation ofthe steam turbine 104, the SEGR gas turbine system control 126 isconfigured to control the system 52, and the machinery control 128 isconfigured to control the machinery 106. Thus, the controller 118 (e.g.,controls 124, 126, and 128) may be configured to coordinate varioussub-systems of the turbine-based service system 14 to provide a suitablestream of the exhaust gas 42 to the hydrocarbon production system 12.

In certain embodiments of the control system 100, each element (e.g.,system, subsystem, and component) illustrated in the drawings ordescribed herein includes (e.g., directly within, upstream, ordownstream of such element) one or more industrial control features,such as sensors and control devices, which are communicatively coupledwith one another over an industrial control network along with thecontroller 118. For example, the control devices associated with eachelement may include a dedicated device controller (e.g., including aprocessor, memory, and control instructions), one or more actuators,valves, switches, and industrial control equipment, which enable controlbased on sensor feedback 130, control signals from the controller 118,control signals from a user, or any combination thereof. Thus, any ofthe control functionality described herein may be implemented withcontrol instructions stored and/or executable by the controller 118,dedicated device controllers associated with each element, or acombination thereof.

In order to facilitate such control functionality, the control system100 includes one or more sensors distributed throughout the system 10 toobtain the sensor feedback 130 for use in execution of the variouscontrols, e.g., the controls 124, 126, and 128. For example, the sensorfeedback 130 may be obtained from sensors distributed throughout theSEGR gas turbine system 52, the machinery 106, the EG processing system54, the steam turbine 104, the hydrocarbon production system 12, or anyother components throughout the turbine-based service system 14 or thehydrocarbon production system 12. For example, the sensor feedback 130may include temperature feedback, pressure feedback, flow rate feedback,flame temperature feedback, combustion dynamics feedback, intake oxidantcomposition feedback, intake fuel composition feedback, exhaustcomposition feedback, the output level of mechanical power 72, theoutput level of electrical power 74, the output quantity of the exhaustgas 42, 60, the output quantity or quality of the water 64, or anycombination thereof. For example, the sensor feedback 130 may include acomposition of the exhaust gas 42, 60 to facilitate stoichiometriccombustion in the SEGR gas turbine system 52. For example, the sensorfeedback 130 may include feedback from one or more intake oxidantsensors along an oxidant supply path of the oxidant 68, one or moreintake fuel sensors along a fuel supply path of the fuel 70, and one ormore exhaust emissions sensors disposed along the exhaust recirculationpath 110 and/or within the SEGR gas turbine system 52. The intakeoxidant sensors, intake fuel sensors, and exhaust emissions sensors mayinclude temperature sensors, pressure sensors, flow rate sensors, andcomposition sensors. The emissions sensors may includes sensors fornitrogen oxides (e.g., NO_(X) sensors), carbon oxides (e.g., CO sensorsand CO₂ sensors), sulfur oxides (e.g., SO_(X) sensors), hydrogen (e.g.,H₂ sensors), oxygen (e.g., O₂ sensors), unburnt hydrocarbons (e.g., HCsensors), or other products of incomplete combustion, or any combinationthereof.

Using this feedback 130, the control system 100 may adjust (e.g.,increase, decrease, or maintain) the intake flow of exhaust gas 66,oxidant 68, and/or fuel 70 into the SEGR gas turbine system 52 (amongother operational parameters) to maintain the equivalence ratio within asuitable range, e.g., between approximately 0.95 to approximately 1.05,between approximately 0.95 to approximately 1.0, between approximately1.0 to approximately 1.05, or substantially at 1.0. For example, thecontrol system 100 may analyze the feedback 130 to monitor the exhaustemissions (e.g., concentration levels of nitrogen oxides, carbon oxidessuch as CO and CO₂, sulfur oxides, hydrogen, oxygen, unburnthydrocarbons, and other products of incomplete combustion) and/ordetermine the equivalence ratio, and then control one or more componentsto adjust the exhaust emissions (e.g., concentration levels in theexhaust gas 42) and/or the equivalence ratio. The controlled componentsmay include any of the components illustrated and described withreference to the drawings, including but not limited to, valves alongthe supply paths for the oxidant 68, the fuel 70, and the exhaust gas66; an oxidant compressor, a fuel pump, or any components in the EGprocessing system 54; any components of the SEGR gas turbine system 52,or any combination thereof. The controlled components may adjust (e.g.,increase, decrease, or maintain) the flow rates, temperatures,pressures, or percentages (e.g., equivalence ratio) of the oxidant 68,the fuel 70, and the exhaust gas 66 that combust within the SEGR gasturbine system 52. The controlled components also may include one ormore gas treatment systems, such as catalyst units (e.g., oxidationcatalyst units), supplies for the catalyst units (e.g., oxidation fuel,heat, electricity, etc.), gas purification and/or separation units(e.g., solvent based separators, absorbers, flash tanks, etc.), andfiltration units. The gas treatment systems may help reduce variousexhaust emissions along the exhaust recirculation path 110, a vent path(e.g., exhausted into the atmosphere), or an extraction path to the EGsupply system 78.

In certain embodiments, the control system 100 may analyze the feedback130 and control one or more components to maintain or reduce emissionslevels (e.g., concentration levels in the exhaust gas 42, 60, 95) to atarget range, such as less than approximately 10, 20, 30, 40, 50, 100,200, 300, 400, 500, 1000, 2000, 3000, 4000, 5000, or 10000 parts permillion by volume (ppmv). These target ranges may be the same ordifferent for each of the exhaust emissions, e.g., concentration levelsof nitrogen oxides, carbon monoxide, sulfur oxides, hydrogen, oxygen,unburnt hydrocarbons, and other products of incomplete combustion. Forexample, depending on the equivalence ratio, the control system 100 mayselectively control exhaust emissions (e.g., concentration levels) ofoxidant (e.g., oxygen) within a target range of less than approximately10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 250, 500, 750, or 1000 ppmv;carbon monoxide (CO) within a target range of less than approximately20, 50, 100, 200, 500, 1000, 2500, or 5000 ppmv; and nitrogen oxides(NO_(X)) within a target range of less than approximately 50, 100, 200,300, 400, or 500 ppmv. In certain embodiments operating with asubstantially stoichiometric equivalence ratio, the control system 100may selectively control exhaust emissions (e.g., concentration levels)of oxidant (e.g., oxygen) within a target range of less thanapproximately 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 ppmv; andcarbon monoxide (CO) within a target range of less than approximately500, 1000, 2000, 3000, 4000, or 5000 ppmv. In certain embodimentsoperating with a fuel-lean equivalence ratio (e.g., betweenapproximately 0.95 to 1.0), the control system 100 may selectivelycontrol exhaust emissions (e.g., concentration levels) of oxidant (e.g.,oxygen) within a target range of less than approximately 500, 600, 700,800, 900, 1000, 1100, 1200, 1300, 1400, or 1500 ppmv; carbon monoxide(CO) within a target range of less than approximately 10, 20, 30, 40,50, 60, 70, 80, 90, 100, 150, or 200 ppmv; and nitrogen oxides (e.g.,NO_(X)) within a target range of less than approximately 50, 100, 150,200, 250, 300, 350, or 400 ppmv. The foregoing target ranges are merelyexamples, and are not intended to limit the scope of the disclosedembodiments.

The control system 100 also may be coupled to a local interface 132 anda remote interface 134. For example, the local interface 132 may includea computer workstation disposed on-site at the turbine-based servicesystem 14 and/or the hydrocarbon production system 12. In contrast, theremote interface 134 may include a computer workstation disposedoff-site from the turbine-based service system 14 and the hydrocarbonproduction system 12, such as through an internet connection. Theseinterfaces 132 and 134 facilitate monitoring and control of theturbine-based service system 14, such as through one or more graphicaldisplays of sensor feedback 130, operational parameters, and so forth.

Again, as noted above, the controller 118 includes a variety of controls124, 126, and 128 to facilitate control of the turbine-based servicesystem 14. The steam turbine control 124 may receive the sensor feedback130 and output control commands to facilitate operation of the steamturbine 104. For example, the steam turbine control 124 may receive thesensor feedback 130 from the HRSG 56, the machinery 106, temperature andpressure sensors along a path of the steam 62, temperature and pressuresensors along a path of the water 108, and various sensors indicative ofthe mechanical power 72 and the electrical power 74. Likewise, the SEGRgas turbine system control 126 may receive sensor feedback 130 from oneor more sensors disposed along the SEGR gas turbine system 52, themachinery 106, the EG processing system 54, or any combination thereof.For example, the sensor feedback 130 may be obtained from temperaturesensors, pressure sensors, clearance sensors, vibration sensors, flamesensors, fuel composition sensors, exhaust gas composition sensors, orany combination thereof, disposed within or external to the SEGR gasturbine system 52. Finally, the machinery control 128 may receive sensorfeedback 130 from various sensors associated with the mechanical power72 and the electrical power 74, as well as sensors disposed within themachinery 106. Each of these controls 124, 126, and 128 uses the sensorfeedback 130 to improve operation of the turbine-based service system14.

In the illustrated embodiment, the SEGR gas turbine system control 126may execute instructions to control the quantity and quality of theexhaust gas 42, 60, 95 in the EG processing system 54, the EG supplysystem 78, the hydrocarbon production system 12, and/or the othersystems 84. For example, the SEGR gas turbine system control 126 maymaintain a level of oxidant (e.g., oxygen) and/or unburnt fuel in theexhaust gas 60 below a threshold suitable for use with the exhaust gasinjection EOR system 112. In certain embodiments, the threshold levelsmay be less than 1, 2, 3, 4, or 5 percent of oxidant (e.g., oxygen)and/or unburnt fuel by volume of the exhaust gas 42, 60; or thethreshold levels of oxidant (e.g., oxygen) and/or unburnt fuel (andother exhaust emissions) may be less than approximately 10, 20, 30, 40,50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or5000 parts per million by volume (ppmv) in the exhaust gas 42, 60. Byfurther example, in order to achieve these low levels of oxidant (e.g.,oxygen) and/or unburnt fuel, the SEGR gas turbine system control 126 maymaintain an equivalence ratio for combustion in the SEGR gas turbinesystem 52 between approximately 0.95 and approximately 1.05. The SEGRgas turbine system control 126 also may control the EG extraction system80 and the EG treatment system 82 to maintain the temperature, pressure,flow rate, and gas composition of the exhaust gas 42, 60, 95 withinsuitable ranges for the exhaust gas injection EOR system 112, thepipeline 86, the storage tank 88, and the carbon sequestration system90. As discussed above, the EG treatment system 82 may be controlled topurify and/or separate the exhaust gas 42 into one or more gas streams95, such as the CO₂ rich, N₂ lean stream 96, the intermediateconcentration CO₂, N₂ stream 97, and the CO₂ lean, N₂ rich stream 98. Inaddition to controls for the exhaust gas 42, 60, and 95, the controls124, 126, and 128 may execute one or more instructions to maintain themechanical power 72 within a suitable power range, or maintain theelectrical power 74 within a suitable frequency and power range.

FIG. 3 is a diagram of embodiment of the system 10, further illustratingdetails of the SEGR gas turbine system 52 for use with the hydrocarbonproduction system 12 and/or other systems 84. In the illustratedembodiment, the SEGR gas turbine system 52 includes a gas turbine engine150 coupled to the EG processing system 54. The illustrated gas turbineengine 150 includes a compressor section 152, a combustor section 154,and an expander section or turbine section 156. The compressor section152 includes one or more exhaust gas compressors or compressor stages158, such as 1 to 20 stages of rotary compressor blades disposed in aseries arrangement. Likewise, the combustor section 154 includes one ormore combustors 160, such as 1 to 20 combustors 160 distributedcircumferentially about a rotational axis 162 of the SEGR gas turbinesystem 52. Furthermore, each combustor 160 may include one or more fuelnozzles 164 configured to inject the exhaust gas 66, the oxidant 68,and/or the fuel 70. For example, a head end portion 166 of eachcombustor 160 may house 1, 2, 3, 4, 5, 6, or more fuel nozzles 164,which may inject streams or mixtures of the exhaust gas 66, the oxidant68, and/or the fuel 70 into a combustion portion 168 (e.g., combustionchamber) of the combustor 160.

The fuel nozzles 164 may include any combination of premix fuel nozzles164 (e.g., configured to premix the oxidant 68 and fuel 70 forgeneration of an oxidant/fuel premix flame) and/or diffusion fuelnozzles 164 (e.g., configured to inject separate flows of the oxidant 68and fuel 70 for generation of an oxidant/fuel diffusion flame).Embodiments of the premix fuel nozzles 164 may include swirl vanes,mixing chambers, or other features to internally mix the oxidant 68 andfuel 70 within the nozzles 164, prior to injection and combustion in thecombustion chamber 168. The premix fuel nozzles 164 also may receive atleast some partially mixed oxidant 68 and fuel 70. In certainembodiments, each diffusion fuel nozzle 164 may isolate flows of theoxidant 68 and the fuel 70 until the point of injection, while alsoisolating flows of one or more diluents (e.g., the exhaust gas 66,steam, nitrogen, or another inert gas) until the point of injection. Inother embodiments, each diffusion fuel nozzle 164 may isolate flows ofthe oxidant 68 and the fuel 70 until the point of injection, whilepartially mixing one or more diluents (e.g., the exhaust gas 66, steam,nitrogen, or another inert gas) with the oxidant 68 and/or the fuel 70prior to the point of injection. In addition, one or more diluents(e.g., the exhaust gas 66, steam, nitrogen, or another inert gas) may beinjected into the combustor (e.g., into the hot products of combustion)either at or downstream from the combustion zone, thereby helping toreduce the temperature of the hot products of combustion and reduceemissions of NO_(X) (e.g., NO and NO₂). Regardless of the type of fuelnozzle 164, the SEGR gas turbine system 52 may be controlled to providesubstantially stoichiometric combustion of the oxidant 68 and fuel 70.

In diffusion combustion embodiments using the diffusion fuel nozzles164, the fuel 70 and oxidant 68 generally do not mix upstream from thediffusion flame, but rather the fuel 70 and oxidant 68 mix and reactdirectly at the flame surface and/or the flame surface exists at thelocation of mixing between the fuel 70 and oxidant 68. In particular,the fuel 70 and oxidant 68 separately approach the flame surface (ordiffusion boundary/interface), and then diffuse (e.g., via molecular andviscous diffusion) along the flame surface (or diffusionboundary/interface) to generate the diffusion flame. It is noteworthythat the fuel 70 and oxidant 68 may be at a substantially stoichiometricratio along this flame surface (or diffusion boundary/interface), whichmay result in a greater flame temperature (e.g., a peak flametemperature) along this flame surface. The stoichiometric fuel/oxidantratio generally results in a greater flame temperature (e.g., a peakflame temperature), as compared with a fuel-lean or fuel-richfuel/oxidant ratio. As a result, the diffusion flame may besubstantially more stable than a premix flame, because the diffusion offuel 70 and oxidant 68 helps to maintain a stoichiometric ratio (andgreater temperature) along the flame surface. Although greater flametemperatures can also lead to greater exhaust emissions, such as NO_(X)emissions, the disclosed embodiments use one or more diluents to helpcontrol the temperature and emissions while still avoiding any premixingof the fuel 70 and oxidant 68. For example, the disclosed embodimentsmay introduce one or more diluents separate from the fuel 70 and oxidant68 (e.g., after the point of combustion and/or downstream from thediffusion flame), thereby helping to reduce the temperature and reducethe emissions (e.g., NO_(X) emissions) produced by the diffusion flame.

In operation, as illustrated, the compressor section 152 receives andcompresses the exhaust gas 66 from the EG processing system 54, andoutputs a compressed exhaust gas 170 to each of the combustors 160 inthe combustor section 154. Upon combustion of the fuel 60, oxidant 68,and exhaust gas 170 within each combustor 160, additional exhaust gas orproducts of combustion 172 (i.e., combustion gas) is routed into theturbine section 156. Similar to the compressor section 152, the turbinesection 156 includes one or more turbines or turbine stages 174, whichmay include a series of rotary turbine blades. These turbine blades arethen driven by the products of combustion 172 generated in the combustorsection 154, thereby driving rotation of a shaft 176 coupled to themachinery 106. Again, the machinery 106 may include a variety ofequipment coupled to either end of the SEGR gas turbine system 52, suchas machinery 106, 178 coupled to the turbine section 156 and/ormachinery 106, 180 coupled to the compressor section 152. In certainembodiments, the machinery 106, 178, 180 may include one or moreelectrical generators, oxidant compressors for the oxidant 68, fuelpumps for the fuel 70, gear boxes, or additional drives (e.g. steamturbine 104, electrical motor, etc.) coupled to the SEGR gas turbinesystem 52. Non-limiting examples are discussed in further detail belowwith reference to TABLE 1. As illustrated, the turbine section 156outputs the exhaust gas 60 to recirculate along the exhaustrecirculation path 110 from an exhaust outlet 182 of the turbine section156 to an exhaust inlet 184 into the compressor section 152. Along theexhaust recirculation path 110, the exhaust gas 60 passes through the EGprocessing system 54 (e.g., the HRSG 56 and/or the EGR system 58) asdiscussed in detail above.

Again, each combustor 160 in the combustor section 154 receives, mixes,and stoichiometrically combusts the compressed exhaust gas 170, theoxidant 68, and the fuel 70 to produce the additional exhaust gas orproducts of combustion 172 to drive the turbine section 156. In certainembodiments, the oxidant 68 is compressed by an oxidant compressionsystem 186, such as a main oxidant compression (MOC) system (e.g., amain air compression (MAC) system) having one or more oxidantcompressors (MOCs). The oxidant compression system 186 includes anoxidant compressor 188 coupled to a drive 190. For example, the drive190 may include an electric motor, a combustion engine, or anycombination thereof. In certain embodiments, the drive 190 may be aturbine engine, such as the gas turbine engine 150. Accordingly, theoxidant compression system 186 may be an integral part of the machinery106. In other words, the compressor 188 may be directly or indirectlydriven by the mechanical power 72 supplied by the shaft 176 of the gasturbine engine 150. In such an embodiment, the drive 190 may beexcluded, because the compressor 188 relies on the power output from theturbine engine 150. However, in certain embodiments employing more thanone oxidant compressor is employed, a first oxidant compressor (e.g., alow pressure (LP) oxidant compressor) may be driven by the drive 190while the shaft 176 drives a second oxidant compressor (e.g., a highpressure (HP) oxidant compressor), or vice versa. For example, inanother embodiment, the HP MOC is driven by the drive 190 and the LPoxidant compressor is driven by the shaft 176. In the illustratedembodiment, the oxidant compression system 186 is separate from themachinery 106. In each of these embodiments, the compression system 186compresses and supplies the oxidant 68 to the fuel nozzles 164 and thecombustors 160. Accordingly, some or all of the machinery 106, 178, 180may be configured to increase the operational efficiency of thecompression system 186 (e.g., the compressor 188 and/or additionalcompressors).

The variety of components of the machinery 106, indicated by elementnumbers 106A, 106B, 106C, 106D, 106E, and 106F, may be disposed alongthe line of the shaft 176 and/or parallel to the line of the shaft 176in one or more series arrangements, parallel arrangements, or anycombination of series and parallel arrangements. For example, themachinery 106, 178, 180 (e.g., 106A through 106F) may include any seriesand/or parallel arrangement, in any order, of: one or more gearboxes(e.g., parallel shaft, epicyclic gearboxes), one or more compressors(e.g., oxidant compressors, booster compressors such as EG boostercompressors), one or more power generation units (e.g., electricalgenerators), one or more drives (e.g., steam turbine engines, electricalmotors), heat exchange units (e.g., direct or indirect heat exchangers),clutches, or any combination thereof. The compressors may include axialcompressors, radial or centrifugal compressors, or any combinationthereof, each having one or more compression stages. Regarding the heatexchangers, direct heat exchangers may include spray coolers (e.g.,spray intercoolers), which inject a liquid spray into a gas flow (e.g.,oxidant flow) for direct cooling of the gas flow. Indirect heatexchangers may include at least one wall (e.g., a shell and tube heatexchanger) separating first and second flows, such as a fluid flow(e.g., oxidant flow) separated from a coolant flow (e.g., water, air,refrigerant, or any other liquid or gas coolant), wherein the coolantflow transfers heat from the fluid flow without any direct contact.Examples of indirect heat exchangers include intercooler heat exchangersand heat recovery units, such as heat recovery steam generators. Theheat exchangers also may include heaters. As discussed in further detailbelow, each of these machinery components may be used in variouscombinations as indicated by the non-limiting examples set forth inTABLE 1.

Generally, the machinery 106, 178, 180 may be configured to increase theefficiency of the compression system 186 by, for example, adjustingoperational speeds of one or more oxidant compressors in the system 186,facilitating compression of the oxidant 68 through cooling, and/orextraction of surplus power. The disclosed embodiments are intended toinclude any and all permutations of the foregoing components in themachinery 106, 178, 180 in series and parallel arrangements, whereinone, more than one, all, or none of the components derive power from theshaft 176. As illustrated below, TABLE 1 depicts some non-limitingexamples of arrangements of the machinery 106, 178, 180 disposedproximate and/or coupled to the compressor and turbine sections 152,156.

TABLE 1 106A 106B 106C 106D 106E 106F MOC GEN MOC GBX GEN LP HP GEN MOCMOC HP GBX LP GEN MOC MOC MOC GBX GEN MOC HP GBX GEN LP MOC MOC MOC GBXGEN MOC GBX DRV DRV GBX LP HP GBX GEN MOC MOC DRV GBX HP LP GEN MOC MOCHP GBX LP GEN MOC CLR MOC HP GBX LP GBX GEN MOC CLR MOC HP GBX LP GENMOC HTR MOC STGN MOC GEN DRV MOC DRV GEN DRV MOC GEN DRV CLU MOC GEN DRVCLU MOC GBX GEN

As illustrated above in TABLE 1, a cooling unit is represented as CLR, aclutch is represented as CLU, a drive is represented by DRV, a gearboxis represented as GBX, a generator is represented by GEN, a heating unitis represented by HTR, a main oxidant compressor unit is represented byMOC, with low pressure and high pressure variants being represented asLP MOC and HP MOC, respectively, and a steam generator unit isrepresented as STGN. Although TABLE 1 illustrates the machinery 106,178, 180 in sequence toward the compressor section 152 or the turbinesection 156, TABLE 1 is also intended to cover the reverse sequence ofthe machinery 106, 178, 180. In TABLE 1, any cell including two or morecomponents is intended to cover a parallel arrangement of thecomponents. TABLE 1 is not intended to exclude any non-illustratedpermutations of the machinery 106, 178, 180. These components of themachinery 106, 178, 180 may enable feedback control of temperature,pressure, and flow rate of the oxidant 68 sent to the gas turbine engine150. As discussed in further detail below, the oxidant 68 and the fuel70 may be supplied to the gas turbine engine 150 at locationsspecifically selected to facilitate isolation and extraction of thecompressed exhaust gas 170 without any oxidant 68 or fuel 70 degradingthe quality of the exhaust gas 170.

The EG supply system 78, as illustrated in FIG. 3, is disposed betweenthe gas turbine engine 150 and the target systems (e.g., the hydrocarbonproduction system 12 and the other systems 84). In particular, the EGsupply system 78, e.g., the EG extraction system (EGES) 80), may becoupled to the gas turbine engine 150 at one or more extraction points76 along the compressor section 152, the combustor section 154, and/orthe turbine section 156. For example, the extraction points 76 may belocated between adjacent compressor stages, such as 2, 3, 4, 5, 6, 7, 8,9, or 10 interstage extraction points 76 between compressor stages. Eachof these interstage extraction points 76 provides a differenttemperature and pressure of the extracted exhaust gas 42. Similarly, theextraction points 76 may be located between adjacent turbine stages,such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points 76between turbine stages. Each of these interstage extraction points 76provides a different temperature and pressure of the extracted exhaustgas 42. By further example, the extraction points 76 may be located at amultitude of locations throughout the combustor section 154, which mayprovide different temperatures, pressures, flow rates, and gascompositions. Each of these extraction points 76 may include an EGextraction conduit, one or more valves, sensors, and controls, which maybe used to selectively control the flow of the extracted exhaust gas 42to the EG supply system 78.

The extracted exhaust gas 42, which is distributed by the EG supplysystem 78, has a controlled composition suitable for the target systems(e.g., the hydrocarbon production system 12 and the other systems 84).For example, at each of these extraction points 76, the exhaust gas 170may be substantially isolated from injection points (or flows) of theoxidant 68 and the fuel 70. In other words, the EG supply system 78 maybe specifically designed to extract the exhaust gas 170 from the gasturbine engine 150 without any added oxidant 68 or fuel 70. Furthermore,in view of the stoichiometric combustion in each of the combustors 160,the extracted exhaust gas 42 may be substantially free of oxygen andfuel. The EG supply system 78 may route the extracted exhaust gas 42directly or indirectly to the hydrocarbon production system 12 and/orother systems 84 for use in various processes, such as enhanced oilrecovery, carbon sequestration, storage, or transport to an offsitelocation. However, in certain embodiments, the EG supply system 78includes the EG treatment system (EGTS) 82 for further treatment of theexhaust gas 42, prior to use with the target systems. For example, theEG treatment system 82 may purify and/or separate the exhaust gas 42into one or more streams 95, such as the CO₂ rich, N₂ lean stream 96,the intermediate concentration CO₂, N₂ stream 97, and the CO₂ lean, N₂rich stream 98. These treated exhaust gas streams 95 may be usedindividually, or in any combination, with the hydrocarbon productionsystem 12 and the other systems 84 (e.g., the pipeline 86, the storagetank 88, and the carbon sequestration system 90).

Similar to the exhaust gas treatments performed in the EG supply system78, the EG processing system 54 may include a plurality of exhaust gas(EG) treatment components 192, such as indicated by element numbers 194,196, 198, 200, 202, 204, 206, 208, and 210. These EG treatmentcomponents 192 (e.g., 194 through 210) may be disposed along the exhaustrecirculation path 110 in one or more series arrangements, parallelarrangements, or any combination of series and parallel arrangements.For example, the EG treatment components 192 (e.g., 194 through 210) mayinclude any series and/or parallel arrangement, in any order, of: one ormore heat exchangers (e.g., heat recovery units such as heat recoverysteam generators, condensers, coolers, or heaters), catalyst systems(e.g., oxidation catalyst systems), particulate and/or water removalsystems (e.g., inertial separators, coalescing filters, waterimpermeable filters, and other filters), chemical injection systems,solvent based treatment systems (e.g., absorbers, flash tanks, etc.),carbon capture systems, gas separation systems, gas purificationsystems, and/or a solvent based treatment system, or any combinationthereof. In certain embodiments, the catalyst systems may include anoxidation catalyst, a carbon monoxide reduction catalyst, a nitrogenoxides reduction catalyst, an aluminum oxide, a zirconium oxide, asilicone oxide, a titanium oxide, a platinum oxide, a palladium oxide, acobalt oxide, or a mixed metal oxide, or a combination thereof. Thedisclosed embodiments are intended to include any and all permutationsof the foregoing components 192 in series and parallel arrangements. Asillustrated below, TABLE 2 depicts some non-limiting examples ofarrangements of the components 192 along the exhaust recirculation path110.

TABLE 2 194 196 198 200 202 204 206 208 210 CU HRU BB MRU PRU CU HRU HRUBB MRU PRU DIL CU HRSG HRSG BB MRU PRU OCU HRU OCU HRU OCU BB MRU PRUHRU HRU BB MRU PRU CU CU HRSG HRSG BB MRU PRU DIL OCU OCU OCU HRSG OCUHRSG OCU BB MRU PRU DIL OCU OCU OCU HRSG HRSG BB COND INER WFIL CFIL DILST ST OCU OCU BB COND INER FIL DIL HRSG HRSG ST ST OCU HRSG HRSG OCU BBMRU MRU PRU PRU ST ST HE WFIL INER FIL COND CFIL CU HRU HRU HRU BB MRUPRU PRU DIL COND COND COND HE INER FIL COND CFIL WFIL

As illustrated above in TABLE 2, a catalyst unit is represented by CU,an oxidation catalyst unit is represented by OCU, a booster blower isrepresented by BB, a heat exchanger is represented by HX, a heatrecovery unit is represented by HRU, a heat recovery steam generator isrepresented by HRSG, a condenser is represented by COND, a steam turbineis represented by ST, a particulate removal unit is represented by PRU,a moisture removal unit is represented by MRU, a filter is representedby FIL, a coalescing filter is represented by CFIL, a water impermeablefilter is represented by WFIL, an inertial separator is represented byINER, and a diluent supply system (e.g., steam, nitrogen, or other inertgas) is represented by DIL. Although TABLE 2 illustrates the components192 in sequence from the exhaust outlet 182 of the turbine section 156toward the exhaust inlet 184 of the compressor section 152, TABLE 2 isalso intended to cover the reverse sequence of the illustratedcomponents 192. In TABLE 2, any cell including two or more components isintended to cover an integrated unit with the components, a parallelarrangement of the components, or any combination thereof. Furthermore,in context of TABLE 2, the HRU, the HRSG, and the COND are examples ofthe HE; the HRSG is an example of the HRU; the COND, WFIL, and CFIL areexamples of the WRU; the INER, FIL, WFIL, and CFIL are examples of thePRU; and the WFIL and CFIL are examples of the FIL. Again, TABLE 2 isnot intended to exclude any non-illustrated permutations of thecomponents 192. In certain embodiments, the illustrated components 192(e.g., 194 through 210) may be partially or completed integrated withinthe HRSG 56, the EGR system 58, or any combination thereof. These EGtreatment components 192 may enable feedback control of temperature,pressure, flow rate, and gas composition, while also removing moistureand particulates from the exhaust gas 60. Furthermore, the treatedexhaust gas 60 may be extracted at one or more extraction points 76 foruse in the EG supply system 78 and/or recirculated to the exhaust inlet184 of the compressor section 152.

As the treated, recirculated exhaust gas 66 passes through thecompressor section 152, the SEGR gas turbine system 52 may bleed off aportion of the compressed exhaust gas along one or more lines 212 (e.g.,bleed conduits or bypass conduits). Each line 212 may route the exhaustgas into one or more heat exchangers 214 (e.g., cooling units), therebycooling the exhaust gas for recirculation back into the SEGR gas turbinesystem 52. For example, after passing through the heat exchanger 214, aportion of the cooled exhaust gas may be routed to the turbine section156 along line 212 for cooling and/or sealing of the turbine casing,turbine shrouds, bearings, and other components. In such an embodiment,the SEGR gas turbine system 52 does not route any oxidant 68 (or otherpotential contaminants) through the turbine section 156 for coolingand/or sealing purposes, and thus any leakage of the cooled exhaust gaswill not contaminate the hot products of combustion (e.g., workingexhaust gas) flowing through and driving the turbine stages of theturbine section 156. By further example, after passing through the heatexchanger 214, a portion of the cooled exhaust gas may be routed alongline 216 (e.g., return conduit) to an upstream compressor stage of thecompressor section 152, thereby improving the efficiency of compressionby the compressor section 152. In such an embodiment, the heat exchanger214 may be configured as an interstage cooling unit for the compressorsection 152. In this manner, the cooled exhaust gas helps to increasethe operational efficiency of the SEGR gas turbine system 52, whilesimultaneously helping to maintain the purity of the exhaust gas (e.g.,substantially free of oxidant and fuel).

FIG. 4 is a flow chart of an embodiment of an operational process 220 ofthe system 10 illustrated in FIGS. 1-3. In certain embodiments, theprocess 220 may be a computer implemented process, which accesses one ormore instructions stored on the memory 122 and executes the instructionson the processor 120 of the controller 118 shown in FIG. 2. For example,each step in the process 220 may include instructions executable by thecontroller 118 of the control system 100 described with reference toFIG. 2.

The process 220 may begin by initiating a startup mode of the SEGR gasturbine system 52 of FIGS. 1-3, as indicated by block 222. For example,the startup mode may involve a gradual ramp up of the SEGR gas turbinesystem 52 to maintain thermal gradients, vibration, and clearance (e.g.,between rotating and stationary parts) within acceptable thresholds. Forexample, during the startup mode 222, the process 220 may begin tosupply a compressed oxidant 68 to the combustors 160 and the fuelnozzles 164 of the combustor section 154, as indicated by block 224. Incertain embodiments, the compressed oxidant may include a compressedair, oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogenmixtures, or any combination thereof. For example, the oxidant 68 may becompressed by the oxidant compression system 186 illustrated in FIG. 3.The process 220 also may begin to supply fuel to the combustors 160 andthe fuel nozzles 164 during the startup mode 222, as indicated by block226. During the startup mode 222, the process 220 also may begin tosupply exhaust gas (as available) to the combustors 160 and the fuelnozzles 164, as indicated by block 228. For example, the fuel nozzles164 may produce one or more diffusion flames, premix flames, or acombination of diffusion and premix flames. During the startup mode 222,the exhaust gas 60 being generated by the gas turbine engine 156 may beinsufficient or unstable in quantity and/or quality. Accordingly, duringthe startup mode, the process 220 may supply the exhaust gas 66 from oneor more storage units (e.g., storage tank 88), the pipeline 86, otherSEGR gas turbine systems 52, or other exhaust gas sources.

The process 220 may then combust a mixture of the compressed oxidant,fuel, and exhaust gas in the combustors 160 to produce hot combustiongas 172, as indicated by block 230. In particular, the process 220 maybe controlled by the control system 100 of FIG. 2 to facilitatestoichiometric combustion (e.g., stoichiometric diffusion combustion,premix combustion, or both) of the mixture in the combustors 160 of thecombustor section 154. However, during the startup mode 222, it may beparticularly difficult to maintain stoichiometric combustion of themixture (and thus low levels of oxidant and unburnt fuel may be presentin the hot combustion gas 172). As a result, in the startup mode 222,the hot combustion gas 172 may have greater amounts of residual oxidant68 and/or fuel 70 than during a steady state mode as discussed infurther detail below. For this reason, the process 220 may execute oneor more control instructions to reduce or eliminate the residual oxidant68 and/or fuel 70 in the hot combustion gas 172 during the startup mode.

The process 220 then drives the turbine section 156 with the hotcombustion gas 172, as indicated by block 232. For example, the hotcombustion gas 172 may drive one or more turbine stages 174 disposedwithin the turbine section 156. Downstream of the turbine section 156,the process 220 may treat the exhaust gas 60 from the final turbinestage 174, as indicated by block 234. For example, the exhaust gastreatment 234 may include filtration, catalytic reaction of any residualoxidant 68 and/or fuel 70, chemical treatment, heat recovery with theHRSG 56, and so forth. The process 220 may also recirculate at leastsome of the exhaust gas 60 back to the compressor section 152 of theSEGR gas turbine system 52, as indicated by block 236. For example, theexhaust gas recirculation 236 may involve passage through the exhaustrecirculation path 110 having the EG processing system 54 as illustratedin FIGS. 1-3.

In turn, the recirculated exhaust gas 66 may be compressed in thecompressor section 152, as indicated by block 238. For example, the SEGRgas turbine system 52 may sequentially compress the recirculated exhaustgas 66 in one or more compressor stages 158 of the compressor section152. Subsequently, the compressed exhaust gas 170 may be supplied to thecombustors 160 and fuel nozzles 164, as indicated by block 228. Steps230, 232, 234, 236, and 238 may then repeat, until the process 220eventually transitions to a steady state mode, as indicated by block240. Upon the transition 240, the process 220 may continue to performthe steps 224 through 238, but may also begin to extract the exhaust gas42 via the EG supply system 78, as indicated by block 242. For example,the exhaust gas 42 may be extracted from one or more extraction points76 along the compressor section 152, the combustor section 154, and theturbine section 156 as indicated in FIG. 3. In turn, the process 220 maysupply the extracted exhaust gas 42 from the EG supply system 78 to thehydrocarbon production system 12, as indicated by block 244. Thehydrocarbon production system 12 may then inject the exhaust gas 42 intothe earth 32 for enhanced oil recovery, as indicated by block 246. Forexample, the extracted exhaust gas 42 may be used by the exhaust gasinjection EOR system 112 of the EOR system 18 illustrated in FIGS. 1-3.

FIG. 5 is a diagram of an embodiment of the gas turbine engine 150 usinga protective fluid (e.g., a gas) for cooling, purging, and/or dilutingcavities in various structures and components of the gas turbine engine150. For example, the protective fluid may be an inert gas used forcooling the gas turbine engine 150. As illustrated, one or more sources260 of inert gases may be provided to a gas turbine fluid supply system262, which supplies one or more inert gases 264 to the gas turbineengine 150. For example, an air separation unit (ASU) 266 may receiveair 268 via a compressor 270. The ASU 266 may operate to separate theair 268 into component gases by, for example, distillation techniques.For example, the ASU 266 may separate oxygen 272 from the air 268supplied to it from the compressor 270. Additionally, the ASU 266 mayseparate nitrogen 274, argon 276, or other inert gases 278 from the air268. Any of the gases 274, 276, and/or 278 may be used as one of theinert gases 264 supplied to the gas turbine engine 150 by the fluidsupply system 262.

In other embodiments, a syngas 280, or synthetic gas, may be generatedby a gasification process. The syngas 280 may include a mixture ofcarbon monoxide and hydrogen. The syngas 280 may be supplied to a gastreatment system 282 to remove various impurities or other undesiredcomponents from the syngas 280. In certain embodiments, the treatedsyngas from the gas treatment system 282 may be supplied to a carboncapture system 284, which may remove and process the carbonaceous gas(e.g., carbon dioxide) included in the syngas 280. The carbon capturesystem 284 may include a compressor, a purifier, a pipeline, a storagetank, or any combination thereof. For example, the carbon capture system284 may include gas separators and/or purifiers, such as solvent-basedgas separators and purifiers, for removing or separating carbon dioxidefrom a fluid. Carbon dioxide 286 generated by the carbon capture system284 may be used as one of the inert gases 264 supplied to the gasturbine engine 150 by the fluid supply system 262.

As discussed in detail above, the exhaust gas supply system 78 mayreceive the exhaust gas 42. The exhaust gas supply system 78 may includethe exhaust gas extraction system 80 and the exhaust gas treatmentsystem 82. In certain embodiments, the exhaust gas treatment system 82includes a gas separator 288 and a gas purifier 290, either or both ofwhich may be solvent-based units, such as absorbers, flash tanks, and soforth. The gas separator 288 may separate the exhaust gas 42 into one ormore streams each containing primarily one component. The gas purifier290 may further purify the streams generated by the gas separator 288.For example, the exhaust gas supply system 78 may generate the first,second, and third streams 96, 97, and 98. As discussed above, the firststream 96 may have a first composition that is rich with carbon dioxideand/or lean in nitrogen (e.g., a CO₂ rich, N₂ lean stream). The secondstream 97 may have a second composition that has intermediateconcentration levels of carbon dioxide and/or nitrogen (e.g.,intermediate concentration CO₂, N₂ stream). The third stream 98 may havea third composition that is lean in carbon dioxide and/or rich innitrogen (e.g., a CO₂ lean, N₂ rich steam). One or more of the first,second, or third streams 96, 97, or 98 may be supplied as the inert gas264 to the gas turbine engine 150 via the fluid supply system 262. Inother embodiments, the exhaust gas 42 and/or 60 may be supplied to theexhaust gas processing system 54 to generate the exhaust gas 42, whichmay also be supplied as the inert gas 264 to the gas turbine engine 150.

In further embodiments, one or more pipelines 86 may be used to supplycarbon dioxide 96 and/or nitrogen 98 as the inert gas 264 to the gasturbine engine 150. Additionally or alternatively, one or more storagetanks 88 may be used to store one or more of the carbon dioxide 96,nitrogen 98, or exhaust gas 42. These gases may be supplied from thestorage tanks 88 as the inert gas 264 to the gas turbine engine 150. Thepipelines 86 and/or storage tanks 88 may be used as a secondary sourceof the inert gas 264. For example, in certain embodiments, the inert gas264 may be primarily supplied by the exhaust gas supply system 78 or theexhaust gas processing system 54. However, when the inert gas 264 is notavailable from either system 78 or 54, or when either system 78 or 54 isnot operational (e.g., during startup), the inert gas 264 may besupplied via the pipeline 86 and/or the storage tank 88. Similarly, thepipeline and/or storage tank 88 may be used as a supplemental source ofthe inert gas 264 in embodiments using the ASU 266 or the syngas 280 tosupply the primary source of the inert gas 264. In further embodiments,a first inert gas may be used during startup and a second inert gas maybe used during steady-state conditions.

In certain embodiments, a sensor system 292 may provide the sensorfeedback 130 to the controller 118 of the control system 100.Specifically, the sensor system 292 may include one or more sensors 294disposed on, along, or in conduits conveying the inert gases 264 fromthe sources 260. For example, the sensors 294 may include temperaturesensors, pressure sensors, flow rate sensors, gas composition sensors,or any combination thereof. Examples of gas composition sensors includeoxygen sensors, fuel sensors, or any combination thereof. In certainembodiments, the conduits conveying the inert gases 264 from the sources260 may also include a control element system 296. Specifically, thecontrol element system 296 may include one or more control elements 298,such as control valves, restriction orifices, flow regulators,expanders, compressors, or similar devices. For example, the controlelements 298 may receive output signals 300 from the controller 118 ofthe control system 100 based on the sensor feedback 130. For example,the sensor 294 may indicate a flow rate of the inert gas 264 below adesired threshold. Based on the sensor feedback 130, the controller 118may send the output signal 300 to the control element 298 to furtheropen to increase the flow rate of the inert gas 264. In certainembodiments, the controller 118 may also receive sensor feedback 130from the fluid supply system 262 and/or send output signals 300 to thefluid supply system 262 to facilitate control of the inert gas flow tothe gas turbine engine 150.

The gas turbine fluid supply system 262 may include one or more systemsto process or handle the inert gas 264 supplied by the source 260 priorto supplying the inert gas 264 to the gas turbine engine 150, e.g., forcooling, purging, diluting, and/or fluidily sealing the exhaust sectionof the gas turbine engine 150. Specifically, the fluid supply system 262may include one or more of the systems shown in FIG. 5 and discussedbelow in any series and/or parallel arrangement, in any order. Forexample, the fluid supply system 262 may include a temperature controlsystem 302 to adjust a temperature of the inert gas 264. For example,the temperature control system 302 may include a heater 304, a cooler306, a heat exchanger 308, or any combination thereof. The heatexchanger 308 may be a direct or indirect heat exchanger. For example,direct heat exchangers may employ direct contact with a cooling medium,such as water (e.g., a spray) and indirect heat exchangers may separatefluids via finned tube heat exchangers or the like. The heater 304 maybe used to increase the temperature of the inert gas 264 and the cooler306 may be used to decrease the temperature of the inert gas 264. Theheat exchanger 308 may be used to exchange heat between the inert gas264 and other process streams (e.g., water, steam, etc.) to eitherincrease or decrease the temperature of the inert gas 264. In addition,a pressure/flow control system 310 may be used to adjust a pressureand/or flow rate of the inert gas 264. For example, the pressure/flowcontrol system 310 may include a compressor 312, a blower 314, anexpander 316, a regulator 318, or any combination thereof. Thecompressor 312 may be used to increase the pressure of the inert gas 264and/or adjust the flow rate of the inert gas 264. Similarly, the blower314 may be used to increase the pressure of the inert gas 264 and/oradjust the flow rate of the inert gas 264. The expander 316 may be usedto decrease the pressure of the inert gas 264 and/or adjust the flowrate of the inert gas 264. Similarly, the regulator 318 may be used todecrease the pressure of the inert gas 264 and/or regulate (e.g., makemore constant or uniform) the flow rate of the inert gas 264. In otherembodiments, similar devices, such as control valves, may be used toadjust the pressure and/or flow rate of the inert gas 264.

A moisture removal system 320 may be used to adjust a moisture contentof the inert gas 264. For example, the moisture removal system 320 mayinclude a first moisture removal unit 322 that includes a heat exchanger324, which may include a condenser 326. The heat exchanger 324 (e.g.,condenser 326) may be used to decrease the temperature of the inert gas264, thereby decreasing the amount of moisture capable of beingcontained in the inert gas 264. Thus, excess moisture that condenses inthe moisture removal unit 322 may be removed from the inert gas 264resulting in the inert gas 264 containing less moisture. A secondmoisture removal unit 328 may include a water gas separator (WGS) system330, a water impermeable filter (WFIL) 332, a coalescing filter (CFIL),or any combination thereof. In the WGS system 330, water may be removedvia a variety of chemical, physical, or other means. The WFIL 332 and/orCFIL 334 may be used to directly remove water from the inert gas 264 viafiltration. In addition, a particulate removal system 336 may removeparticulates from the inert gas 264. For example, in a first particulateremoval unit 338, an inertial separator 340 and/or a gravity separator342 may be used to remove particulates from the inert gas 264. In asecond particulate removal unit 344, one or more filters 346 may be usedto remove particulates from the inert gas 264.

By using one or more of the systems 302, 310, 320, and/or 336 in thefluid supply system 262, the quality and/or properties of the inert gas264 may be improved or modified to a desired level for use in protecting(e.g., cooling, purging, and/or fluidly sealing) components in the gasturbine engine 150. For example, as the inert gas 264 is used forcooling in the gas turbine engine 150, reducing the temperature of theinert gas 264 using the temperature control system 302 may be desirableto improve the cooling capacity of the inert gas 264. In addition,certain components of the gas turbine engine 150 may have temperatureand/or pressure limitations. Thus, the temperature control system 302and/or the pressure/flow control system 310 may be used to adjust theproperties of the inert gas 264 to be within the limitations of the gasturbine engine 150. The pressure/flow control system 310 may also beused to adjust the pressure of the inert gas 264 to be higher than thatof the exhaust gas, thereby blocking leakage of the exhaust gas intocavities of the gas turbine engine 150. Similarly, moisture in the gasturbine engine 150 may cause corrosion or other undesired chemicalreactions. Thus, the moisture removal system 320 may be used to removeany moisture contained in the inert gas 264 before being supplied to thegas turbine engine 150. This moisture control system 320 may extend thelife of certain components, such as bearings, while also helping toprotect the oils and/or lubricants. The gas turbine engine 150 may havesmall operating clearances between certain components. Thus, theparticulate removal system 336 may be used to remove particulates thatmay cause damage or other undesired consequences to the components ofthe gas turbine engine 150. In other embodiments, the fluid supplysystem 262 may include other systems to further condition, treat, ormodify the inert gas 264 prior to being supplied to the gas turbineengine 150.

As discussed above, the inert gas 264 may be provided to the gas turbineengine 150 for a variety of purposes. For example, the inert gas 264 maybe used as a cooling gas 348, as discussed in detail below. For example,the cooling gas 348 may be used to cool various components of theturbine section 156. In other embodiments, the inert gas 264 may be usedas a purge gas 350. For example, the purge gas 350 may be used to purgevarious portions of the gas turbine engine 150 for a startup, ashutdown, a turnaround, maintenance, and so forth. In furtherembodiments, the inert gas 264 may be used as a diluent gas 352. Forexample, the diluent gas 352 may be used to decrease NO_(x) emissions ofthe gas turbine engine 150 or otherwise adjust the operating conditionsof the gas turbine engine 150. In these various applications of theinert gas 264, it may be desirable for the inert gas 264 to have littleto no oxygen. Specifically, when the gas turbine engine 150 is part ofthe SEGR gas turbine system 52, it may be desirable to exclude oxygenfrom the exhaust gas 42, such as when the exhaust gas 42 is used in theoil/gas extraction system 16 or the EOR system 18. When the inert gas264 is used for the cooling gas 348, purge gas 350, and/or diluent gas352, some of these gases may enter or combine with the exhaust gas 42.Thus, by using inert gas 264 that has little to no oxygen, the lowoxygen concentration of the exhaust gas 42 may be maintained. Inaddition, the inert gas 264 may have various purity levels, such asapproximately 75, 80, 85, 90, 95, 97.5, or 99 percent purity by volume.

FIG. 6 is a diagram of the gas turbine engine 150 coupled to the gasturbine fluid supply system 262. Elements in FIG. 6 in common with thoseshown in previous figures are labeled with the same reference numerals.The axial direction of the gas turbine engine 150 is indicated by arrow360, the radial direction is indicated by arrow 362, and thecircumferential direction is indicated by arrow 364. These direction areall with respect to the rotational axis 162. In the illustratedembodiment, the turbine section 156 include an upstream end 370 and adownstream end 372. Specifically, the products of combustion 172 enterthe upstream end 370 and exit the downstream end 372 as the exhaust gas60. An exhaust section 374 is disposed downstream from the downstreamend 372 of the turbine section 156. The exhaust section 374 may includebearings associated with the shaft 176. In addition, the exhaust section374 may be used to expand and/or cool the products of combustion 172before venting the exhaust gas 60 to the exhaust recirculation path 110.Thus, the exhaust section 374 may be exposed to high temperatures forprolonged periods. As shown in FIG. 6, the exhaust section 374 mayinclude an exhaust passage 376 in fluid communication with the turbinesection 156 and an inert gas passage 378 coupled to the fluid supplysystem 264. As described in detail below, the products of combustion 172(e.g., exhaust gas 60) may flow through the exhaust passage 376. Theinert gas 264 may flow through the inert gas passage 378 to cool, purge,and/or fluidly seal one or more components of the exhaust section 374before discharging into the exhaust passage 376 and mixing with theexhaust gas 60 of the exhaust section 374. In other words, the inert gaspassage 378 may be fluidly coupled to the exhaust passage 376. In otherembodiments, the inert gas passage 378 may be isolated from the exhaustpassage 376. For example, the inert gas 264 may be discharged from thesystem, and possibly recirculated through the fluid supply system 262.In certain embodiments, a wall 380 may be disposed along the exhaustpassage 376 and the wall 380 may separate the exhaust passage 376 fromthe inert gas passage 378. The wall 380 may extend circumferentially 364(e.g., annular, rectangular, etc.) about the rotational axis 162. Insome embodiments, one or more vanes 382 may protrude into the exhaustpassage 376. The vanes 382 may be used to further route the inert gas264 through the exhaust section 374. For example, the vanes 382 may beused to route the inert gas 264 to a bearing cavity 384 located aboutthe shaft 176. By flowing the inert gas 264 through the passage 378,vanes 382, and/or bearing cavity 384, the inert gas 264 may be used tocool, purge, and/or fluidly seal various components of the exhaustsection 374, thereby increasing the reliability and lifetimes of thecomponents. In addition, as the inert gas 264 is generally low in oxygencontent, use of the inert gas 264 may result in maintaining the lowconcentration of oxygen in the exhaust gas 60, which may be desirablewith SEGR gas turbine systems 52.

FIG. 7 is a cross-sectional view of the exhaust section 374. Elements inFIG. 7 in common with those shown in FIG. 6 are labeled with the samereference numerals. As shown in FIG. 7, the fluid supply system 262supplies the inert gas 264 to various components of the exhaust section374. For example, the inert gas 264 may be supplied to an outer shroudcavity 400 surrounding the exhaust passage 376. The outer shroud cavity400 may be formed by a casing 402 extending circumferentially 364 (e.g.,annular, rectangular, etc.) about an outer shroud 404, which in turnextends circumferentially 364 (e.g., annular, rectangular, etc.) aboutthe exhaust passage 376. In certain embodiments, the casing 402 and theouter shroud 404 may be coaxial or concentric with one another. As shownin FIG. 7, a fluid inlet 398 may extend through the casing 402 toprovide a path for the inert gas 264 to enter the outer shroud cavity400 from the fluid supply system 262. Thus, the outer shroud cavity 400may be used to cool, purge, or fluidly seal the portion of the exhaustsection 374 adjacent the casing 402 and outer shroud 404. In otherwords, the outer shroud cavity 400 is an example of the inert gaspassage 378, and the outer shroud 404 is an example of the wall 380separating the exhaust passage 376 from the inert gas passage 378. Inaddition, the outer shroud cavity 400 may include a plurality ofopenings 406 (e.g., orifices) in the outer shroud 404 to enable theinert gas 264 to enter the exhaust passage 376. In other words, afterthe inert gas 264 flows through and cools, purges, and/or fluidly sealsthe outer shroud cavity 400, the inert gas 264 may combine with theexhaust gas 60 flowing through the exhaust section 374 via the pluralityof openings 406.

In certain embodiments, the exhaust section 374 includes an inner shroudcavity 408 circumferentially 364 surrounded by the exhaust passage 376.Specifically, an inner shroud 410 (e.g., wall 380) may extendcircumferentially 364 about the rotational axis 162 to define the innershroud cavity 408. The exhaust passage 376 extends circumferentially 364about the inner shroud 410, and the inert gas passage 378 extendsthrough the inner shroud cavity 408. The inert gas 264 may be supplieddirectly to the inner shroud cavity 408 radially 362 and/or axially 360(e.g., either along side or end of gas turbine) via one or more fluidinlets 398 or via the vanes 380, as described in detail below. Afterflowing through the inner shroud cavity 408, the inert gas 264 may flowthrough the plurality of openings 406 (e.g., orifices) formed in theinner shroud 410 to combine with the exhaust gas 60 in the exhaustpassage 376. The inert gas 264 may be used to cool, purge, and/orfluidly seal the inner shroud cavity 408.

As shown in FIG. 7, one or more vanes 380 may protrude into the exhaustpassage 376. For example, the vane 380 may extend between (and connectwith both) the outer shroud 404 and the inner shroud 410. Each vane 380may extend radially 362 through the exhaust passage 376. In addition,each vane 380 may include an internal vane cavity 412, and the inert gaspassage 378 may extend through the internal vane cavity 412. Forexample, the inert gas 264 may be routed from the outer shroud cavity400 through at least some of the plurality of openings 406 into theinternal vane cavity 412 before entering the internal shroud cavity 408through the plurality of openings 406 of the inner shroud 410. Thus, thevanes 380 may be used to convey the inert gas 264 from the outer shroudcavity 400 to the inner shroud cavity 408, and to provide cooling,purging, and/or fluid sealing of the vanes 380. In certain embodiments,the inert gas 264 may be provided directly to the vane 380 via one ormore fluid inlets 398 along the exhaust passage 376.

In certain embodiments, the inner shroud 410 extends circumferentially364 about a bearing housing 414. Thus, the inner shroud 410 and thebearing housing 414 may at least partially define the inner shroudcavity 408. In addition, a bearing assembly 416 may be disposed withinthe bearing cavity 384 of the bearing housing 414. Thus, the innershroud cavity 408 may be said to include the space of the bearinghousing 414, assembly 416, and so forth, because the inner shroud cavity408 is mounted within the inner shroud 410. In other embodiments, thebearing assembly 416 may be at least partially disposed within the innershroud cavity 408. The bearing assembly 416 may at least partiallysupport the shaft 176 and may be disposed at various positions along theshaft 176. For example, the bearing assembly 416 may be disposed nearthe downstream end 372 of the turbine section 156, which may also bereferred to as a #2 bearing location. As shown in FIG. 7, the inert gas264 may enter the bearing cavity 384 radially 362 and/or axially 360(e.g., either along side or end of gas turbine) via the fluid inlet 398.The inert gas 264 may circulate throughout the bearing housing 414 tohelp cool, purge, and/or fluidly seal the bearing assembly 416. In otherembodiments, the inert gas 264 may enter the bearing assembly 416directly via the fluid inlet 398. After cooling, purging, and/or fluidlysealing the bearing assembly 416, the inert gas 264 may exit the innershroud cavity 408 via the plurality of openings 406 to mix with theexhaust gas 60 in the exhaust passage 376. The inert gas 264 may also beprovided to the bearing housing 414 via the plurality of openings 406 inthe bearing housing 414. Various lubricants and/or oils may be used inthe bearing assembly 416. Such lubricants and oils may be subject todegradation upon exposure to oxygen, moisture, particulates, etc. Thus,by using the inert gas 264 for cooling, purging, and/or fluidly sealingthe bearing assembly 416, the longevity of the lubricants and oils maybe increased. Alternatively or additionally, less expensive lubricantsand oils may be used for the bearing assembly 416 when the inert gas 264is used for cooling. Although the previous discussion focused on use ofthe inert gas 264 with the exhaust section 374, in other embodiments,the inert gas 264 may be used with other sections of the gas turbineengine 150.

FIG. 8 is a cross-sectional view of the exhaust section 374. Elements inFIG. 8 in common with those shown in FIG. 7 are labeled with the samereference numerals. As shown in FIG. 8, the fluid supply system 262supplies the inert gas 264 to various components of the exhaust section374. For example, the inert gas 264 may be supplied to an aft diffusercavity 430 disposed downstream of the bearing cavity 384 with respect tothe direction of flow of the exhaust gas 60 through the exhaust section374. The casing 402 may extend circumferentially 364 about the outershroud 404, which in turn extends circumferentially 364 about the aftdiffuser cavity 430. In certain embodiments, the aft diffuser cavity 430may be coupled to the bearing cavity 384. As shown in FIG. 8, the inertgas 264 may be supplied to the aft diffuser cavity 430 via a manway 432,which may be used to provide access to the aft diffuser cavity 430 fromoutside of the exhaust section 374. Specifically, the manway 432, whichextends in the radial direction 362, may include an opening 434 formedin the casing 402 and outer shroud 404 coupled to a conduit 436extending through the exhaust passage 376 from the outer shroud 404 tothe aft diffuser cavity 430. The conduit 436 may have a circular, oval,or airfoil-shaped cross-section. The inert gas 264 may enter the manway432 from the fluid supply system 262 via the fluid inlet 398 at theopening 434. In certain embodiments, a seal 438 may be used to blockleakage to the atmosphere of inert gas 264 returning to the manway 432after being used for cooling, purging, and/or diluting, thereby helpingto contain the inert gas 264 and exhaust in the exhaust section 374. Forexample, the seal 438 may be disposed at the opening 434, the fluidinlet 398, or any combination thereof. The seal 438 may be made from anelastomeric material, plastic, fiber, metal, or any other materialcapable of blocking the inert gas 264. Use of the seal 438 may bedesirable in certain embodiments in which the inert gas 264 includesgases that may be undesirable for human exposure, such as when the inertgas 264 includes exhaust gas 60. As personnel may be present adjacent tothe exhaust section 374 during operation of the gas turbine engine 150,the seal 438 may be used to help block the inert gas 264 from reachingpersonnel working in the vicinity of the exhaust section 374.

In certain embodiments, the inert gas 264 flows through the manway 432and into the aft diffuser cavity 430 to provide cooling, purging, and/ordiluting of the aft diffuser cavity 430. The inert gas 264 supplied tothe aft diffuser cavity 430 via the manway 432 may have a temperaturelower than that of the exhaust gas 60. For example, the temperaturecontrol system 302 (e.g., the cooler 306) of the fluid supply system 262may be used to cool exhaust gas 42 to produce the inert gas 264 (e.g.,cooling gas 348). Thus, the inert gas 264 may be used to cool theportions of the exhaust section 374 through which the inert gas 264flows. For example, a difference between the temperature of the exhaustgas 60 and the temperature of the inert gas 264 may be greater thanapproximately 100 degrees Celsius. In certain embodiments, thedifference between the temperature of the exhaust gas 60 and thetemperature of the inert gas 264 may be between approximately 20 to 400degrees Celsius, 50 to 200 degrees Celsius, or 75 to 125 degreesCelsius. After being used for cooling, purging, and/or diluting in theaft diffuser cavity 430, the inert gas 264 may then exit the aftdiffuser cavity 430 through one or more openings 406 to combine with theexhaust gas 60 flowing through the exhaust passage 376. For example, oneor more openings 406 may be formed in a cap 440 of the aft diffusercavity 430. A portion of the inert gas 264 may flow back into the manway432 and then exit through one or more openings 406 formed in the conduit436 to combine with the exhaust gas 60. In further embodiments, a vent442 may be coupled to one or more of the openings 406 to route the inertgas 264 to an inert gas collection system 444. The vent 442 may besealed or made from materials to help block exposure of personnel to theinert gas 264. In addition, the inert gas collection system 444 may bedisposed away from personnel, thereby helping to avoid personnelexposure to the inert gas 264. The inert gas 264 collected by the inertgas collection system 444 may be reused for cooling, purging, and/ordiluting after being routed back to the fluid supply system 262.

As described above, certain embodiments in the gas turbine engine 150may include the turbine section 156 having one or more turbine stages174 between the upstream end 370 and the downstream end 372, the exhaustsection 374 disposed downstream from the downstream end 372, and thefluid supply system 262 coupled to the exhaust section 374. The fluidsupply system 262 routes the inert gas 264 to the exhaust section 374.The inert gas 264 may then be used to provide cooling, purging, and/orfluidly sealing of various components of the exhaust section 374, suchas the outer shroud cavity 400, the inner shroud cavity 408, the vane380, the bearing cavity 384, the bearing assembly 416, or anycombination thereof. After cooling, purging, and/or fluidly sealing thevarious components of the exhaust section 374, the inert gas 264 maycombine with the exhaust gas 60 in the exhaust passage 376. The exhaustgas 60 may then be used for various applications, such as the oil/gasextraction system 16 or the enhanced oil recovery system 18 describedabove. In such applications, it may be desirable for the exhaust gas 60to include little to no oxygen. Thus, use of the inert gas 264 forcooling, purging, and/or fluidly sealing of the exhaust section 374 mayhelp to maintain the low oxygen content of the exhaust gas 60.

Additional Description

The present embodiments provide systems and methods for gas turbineengines. It should be noted that any one or a combination of thefeatures described above may be utilized in any suitable combination.Indeed, all permutations of such combinations are presentlycontemplated. By way of example, the following clauses are offered asfurther description of the present disclosure:

Embodiment 1

A system, comprising: a combustor section having one or more combustorsconfigured to generate combustion products; a turbine section having oneor more turbine stages between an upstream end and a downstream end,wherein the one or more turbine stages are driven by the combustionproducts; an exhaust section disposed downstream from the downstream endof the turbine section, wherein the exhaust section has an exhaustpassage configured to receive the combustion products as an exhaust gas;and a fluid supply system coupled to the exhaust section, wherein thefluid supply system is configured to route a cooling gas to the exhaustsection, wherein the cooling gas has a temperature lower than theexhaust gas, wherein the cooling gas comprises an extracted exhaust gas,a gas separated from the extracted exhaust gas, carbon dioxide, carbonmonoxide, nitrogen oxides, or a combination thereof.

Embodiment 2

The system of embodiment 1, wherein the exhaust section comprises acooling gas passage coupled to the fluid supply system, and the coolinggas passage extends through at least one wall along the exhaust passage.

Embodiment 3

The system defined in any preceding embodiment, wherein the cooling gaspassage is isolated from the exhaust passage.

Embodiment 4

The system defined in any preceding embodiment, wherein the cooling gaspassage is fluidly coupled to the exhaust passage.

Embodiment 5

The system defined in any preceding embodiment, wherein the exhaustsection comprises a wall disposed along the exhaust passage, and thecooling gas passage is fluidly coupled to the exhaust passage through aplurality of openings in the wall.

Embodiment 6

The system defined in any preceding embodiment, wherein the cooling gaspassage extends through at least one of an outer shroud cavitysurrounding the exhaust passage, an inner shroud cavity surrounded bythe exhaust passage, a vane protruding into the exhaust passage, abearing cavity having a bearing assembly, or a combination thereof.

Embodiment 7

The system defined in any preceding embodiment, wherein the exhaustsection comprises: an outer shroud extending circumferentially about theexhaust passage; and a casing extending circumferentially about theouter shroud to define an outer shroud cavity, wherein the cooling gaspassage extends through the outer shroud cavity.

Embodiment 8

The system defined in any preceding embodiment, a vane protruding intothe exhaust passage, wherein the vane comprises an internal vane cavity,and the cooling gas passage extends through the internal vane cavity.

Embodiment 9

The system defined in any preceding embodiment, an inner shroudextending circumferentially about a rotational axis of the gas turbineengine to define an inner shroud cavity, wherein the exhaust passageextends circumferentially about the inner shroud, and the cooling gaspassage extends through the inner shroud cavity.

Embodiment 10

The system defined in any preceding embodiment, comprising a bearingassembly at least partially disposed within the inner shroud cavity.

Embodiment 11

The system defined in any preceding embodiment, wherein the gas turbineengine comprises a bearing assembly disposed within a bearing cavity ofa bearing housing, and the fluid supply system is coupled to the bearinghousing to route the cooling gas to the bearing housing.

Embodiment 12

The system defined in any preceding embodiment, wherein the cooling gascomprises the extracted exhaust gas or the carbon dioxide.

Embodiment 13

The system defined in any preceding embodiment, wherein the fluid supplysystem is coupled to an exhaust gas extraction system, an exhaust gastreatment system, an exhaust gas recirculation system, a carbon capturesystem, a gas separator, a gas purifier, a storage tank, a pipeline, orany combination thereof.

Embodiment 14

The system defined in any preceding embodiment, wherein the fluid supplysystem comprises a temperature control system, a pressure controlsystem, a moisture removal system, a particulate removal system, or anycombination thereof.

Embodiment 15

The system defined in any preceding embodiment, wherein the gas turbineengine comprises: a compressor section having an exhaust gas compressordriven by the turbine section, wherein the exhaust gas compressor isconfigured to compress and route the exhaust gas to the turbinecombustor.

Embodiment 16

The system defined in any preceding embodiment, comprising an exhaustgas extraction system coupled to the gas turbine engine, and ahydrocarbon production system coupled to the exhaust gas extractionsystem.

Embodiment 17

The system defined in any preceding embodiment, wherein the gas turbineengine is a stoichiometric exhaust gas recirculation (SEGR) gas turbineengine.

Embodiment 18

The system defined in any preceding embodiment, wherein the exhaustsection comprises a manway configured to provide access to an interiorof the exhaust section, and wherein the manway comprises a sealconfigured to contain a flow of the cooling gas within the manway.

Embodiment 19

The system defined in any preceding embodiment, wherein the exhaustsection comprises a vent configured to withdraw the cooling gas from theexhaust section.

Embodiment 20

The system defined in any preceding embodiment, wherein a differencebetween a temperature of the exhaust gas and the temperature of thecooling gas is greater than approximately 100 degrees Celsius.

Embodiment 21

The system defined in any preceding embodiment, wherein a differencebetween a temperature of the exhaust gas and the temperature of thecooling gas is between approximately 20 to 400 degrees Celsius.

Embodiment 22

A system, comprising: a turbine exhaust section configured to mountdownstream from a turbine section of a gas turbine engine, wherein theturbine exhaust section comprises an exhaust passage configured toreceive exhaust gas from the turbine section, and a cooling gas passageextending through a structure of the turbine exhaust section; and afluid supply system coupled to the exhaust section, wherein the fluidsupply system is configured to route a cooling gas to the cooling gaspassage in the exhaust section, wherein the cooling gas has atemperature lower than the exhaust gas, wherein the cooling gascomprises an extracted exhaust gas, a gas separated from the extractedexhaust gas, carbon dioxide, carbon monoxide, nitrogen oxides, or acombination thereof.

Embodiment 23

The system defined in any preceding embodiment, comprising the gasturbine engine having the turbine exhaust section coupled to the turbinesection.

Embodiment 24

The system defined in any preceding embodiment, wherein the gas turbineengine comprises: the turbine section having one or more turbine stagesbetween an upstream end and a downstream end; a combustor section havinga turbine combustor configured to generate combustion products to drivethe one or more turbine stages in the turbine section; and a compressorsection having an exhaust gas compressor driven by the turbine section,wherein the exhaust gas compressor is configured to compress and routethe exhaust gas to the turbine combustor; wherein the turbine exhaustsection is coupled to the gas turbine engine downstream from thedownstream end of the turbine section.

Embodiment 25

The system defined in any preceding embodiment, wherein the gas turbineengine is a stoichiometric exhaust gas recirculation (SEGR) gas turbineengine.

Embodiment 26

The system defined in any preceding embodiment, wherein the cooling gaspassage is isolated from the exhaust passage.

Embodiment 27

The system defined in any preceding embodiment, wherein the cooling gaspassage is fluidly coupled to the exhaust passage.

Embodiment 28

The system defined in any preceding embodiment, wherein the exhaustsection comprises a wall disposed along the exhaust passage, and thecooling gas passage is fluidly coupled to the exhaust passage through aplurality of openings in the wall.

Embodiment 29

The system defined in any preceding embodiment, wherein the cooling gaspassage extends through at least one of an outer shroud cavitysurrounding the exhaust passage, an inner shroud cavity surrounded bythe exhaust passage, a vane protruding into the exhaust passage, abearing cavity having a bearing assembly, or a combination thereof.

Embodiment 30

The system defined in any preceding embodiment, wherein the cooling gascomprises the extracted exhaust gas or the carbon dioxide.

Embodiment 31

The system defined in any preceding embodiment, wherein the fluid supplysystem is coupled to an exhaust gas extraction system, an exhaust gastreatment system, an exhaust gas recirculation system, a carbon capturesystem, a gas separator, a gas purifier, a storage tank, a pipeline, orany combination thereof.

Embodiment 32

The system defined in any preceding embodiment, wherein the fluid supplysystem comprises a temperature control system, a pressure controlsystem, a moisture removal system, a particulate removal system, or anycombination thereof.

Embodiment 33

The system defined in any preceding embodiment, wherein the turbineexhaust section comprises a manway configured to provide access to aninterior of the turbine exhaust section, and wherein the manwaycomprises a seal configured to contain a flow of the cooling gas withinthe manway.

Embodiment 34

The system defined in any preceding embodiment, wherein the turbineexhaust section comprises a vent configured to withdraw the cooling gasfrom the turbine exhaust section.

Embodiment 35

The system defined in any preceding embodiment, wherein a differencebetween a temperature of the exhaust gas and the temperature of thecooling gas is greater than approximately 100 degrees Celsius.

Embodiment 36

The system defined in any preceding embodiment, wherein a differencebetween a temperature of the exhaust gas and the temperature of thecooling gas is between approximately 20 to 400 degrees Celsius.

Embodiment 37

A system, comprising: a turbine exhaust section configured to mountdownstream from a turbine section of a gas turbine engine, wherein theturbine exhaust section comprises an exhaust passage configured toreceive exhaust gas from the turbine section, and a cooling gas passageextending through a structure of the turbine exhaust section to route acooling gas to the turbine exhaust section, wherein the cooling gas hasa temperature lower than the exhaust gas, wherein the cooling gascomprises an extracted exhaust gas, a gas separated from the extractedexhaust gas, carbon dioxide, carbon monoxide, nitrogen oxides, or acombination thereof.

Embodiment 38

The system defined in any preceding embodiment, a fluid supply systemcoupled to the exhaust section, wherein the fluid supply system isconfigured to route the cooling gas to the cooling gas passage in theexhaust section.

Embodiment 39

The system defined in any preceding embodiment, comprising the gasturbine engine having the turbine exhaust section coupled to the turbinesection.

Embodiment 40

The system defined in any preceding embodiment, wherein the cooling gaspassage extends through at least one of an outer shroud cavitysurrounding the exhaust passage, an inner shroud cavity surrounded bythe exhaust passage, a vane protruding into the exhaust passage, abearing cavity having a bearing assembly, or a combination thereof.

Embodiment 41

The system defined in any preceding embodiment, wherein the turbineexhaust section comprises a manway configured to provide access to aninterior of the turbine exhaust section, and wherein the manwaycomprises a seal configured to contain a flow of the cooling gas withinthe manway.

Embodiment 42

The system defined in any preceding embodiment, wherein the turbineexhaust section comprises a vent configured to withdraw the cooling gasfrom the turbine exhaust section.

Embodiment 43

A method, comprising: combusting a fuel with an oxidant and an exhaustgas in a combustion portion of a turbine combustor to generatecombustion products; driving a turbine with the combustion products fromthe turbine combustor; expanding and cooling the combustion productsfrom the turbine through an exhaust passage in an exhaust section; androuting a cooling gas from a fluid supply system to the exhaust section,wherein the cooling gas comprises an extracted exhaust gas, a gasseparated from the extracted exhaust gas, carbon dioxide, carbonmonoxide, nitrogen oxides, or a combination thereof.

Embodiment 44

The method or system defined in any preceding embodiment, comprisingrouting the cooling gas from the fluid supply system to an outer shroudcavity of the exhaust section, wherein the outer shroud cavity isdisposed between an outer shroud and a casing of the exhaust section,and the outer shroud extends circumferentially about the exhaustpassage.

Embodiment 45

The method or system defined in any preceding embodiment, comprisingrouting the cooling gas from the fluid supply system to an internal vanecavity of a vane, wherein the vane extends into the exhaust passage ofthe exhaust section.

Embodiment 46

The method or system defined in any preceding embodiment, comprisingrouting the cooling gas from the fluid supply system to an inner shroudcavity of the exhaust section, wherein an inner shroud extendscircumferentially about the inner shroud cavity, and the exhaust passageextends circumferentially about the inner shroud.

Embodiment 47

The method or system defined in any preceding embodiment, comprisingrouting the cooling gas through a bearing cavity of the exhaust section,wherein the bearing cavity comprises a bearing assembly.

Embodiment 48

The method or system defined in any preceding embodiment, whereincombusting comprises stoichiometrically combusting the fuel with theoxidant and the exhaust gas.

Embodiment 49

The method or system defined in any preceding embodiment, comprisingextracting a portion of the exhaust gas, and routing the portion ofexhaust gas to a hydrocarbon production system.

Embodiment 50

The method or system defined in any preceding embodiment, comprisingsealing a flow of the cooling gas within a manway of the exhaustsection.

Embodiment 51

The method or system defined in any preceding embodiment, comprisingventing the cooling gas from the turbine exhaust section aftercirculating the cooling gas through at least one cavity.

Embodiment 52

The method or system defined in any preceding embodiment, wherein thegas turbine engine is configured to combust a mixture of a fuel and anoxidant with an equivalence ratio of approximately 0.95 to approximately1.05.

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to practice the invention, including making and using any devices orsystems and performing any incorporated methods. The patentable scope ofthe invention is defined by the claims, and may include other examplesthat occur to those skilled in the art. Such other examples are intendedto be within the scope of the claims if they have structural elementsthat do not differ from the literal language of the claims, or if theyinclude equivalent structural elements with insubstantial differencesfrom the literal language of the claims.

1. A system, comprising: a gas turbine engine, comprising: a combustorsection having one or more combustors configured to generate combustionproducts; a turbine section having one or more turbine stages between anupstream end and a downstream end, wherein the one or more turbinestages are driven by the combustion products; an exhaust sectiondisposed downstream from the downstream end of the turbine section,wherein the exhaust section has an exhaust passage configured to receivethe combustion products as an exhaust gas; and a fluid supply systemcoupled to the exhaust section, wherein the fluid supply system isconfigured to route a cooling gas to the exhaust section, wherein thecooling gas has a temperature lower than the exhaust gas, wherein thecooling gas comprises an extracted exhaust gas, a gas separated from theextracted exhaust gas, carbon dioxide, carbon monoxide, nitrogen oxides,or a combination thereof.
 2. The system of claim 1, wherein the exhaustsection comprises a cooling gas passage coupled to the fluid supplysystem, and the cooling gas passage extends through at least one wallalong the exhaust passage. 3.-5. (canceled)
 6. The system of claim 2,wherein the cooling gas passage extends through at least one of an outershroud cavity surrounding the exhaust passage, an inner shroud cavitysurrounded by the exhaust passage, a vane protruding into the exhaustpassage, a bearing cavity having a bearing assembly, or a combinationthereof. 7-10. (canceled)
 11. The system of claim 1, wherein the gasturbine engine comprises a bearing assembly disposed within a bearingcavity of a bearing housing, and the fluid supply system is coupled tothe bearing housing to route the cooling gas to the bearing housing. 12.(canceled)
 13. The system of claim 1, wherein the fluid supply system iscoupled to an exhaust gas extraction system, an exhaust gas treatmentsystem, an exhaust gas recirculation system, a carbon capture system, agas separator, a gas purifier, a storage tank, a pipeline, or anycombination thereof.
 14. (canceled)
 15. The system of claim 1, whereinthe gas turbine engine comprises: a compressor section having an exhaustgas compressor driven by the turbine section, wherein the exhaust gascompressor is configured to compress and route the exhaust gas to theturbine combustor.
 16. The system of claim 15, comprising an exhaust gasextraction system coupled to the gas turbine engine, and a hydrocarbonproduction system coupled to the exhaust gas extraction system.
 17. Thesystem of claim 15, wherein the gas turbine engine is a stoichiometricexhaust gas recirculation (SEGR) gas turbine engine. 18.-21. (canceled)22. A system, comprising: a turbine exhaust section configured to mountdownstream from a turbine section of a gas turbine engine, wherein theturbine exhaust section comprises an exhaust passage configured toreceive exhaust gas from the turbine section, and a cooling gas passageextending through a structure of the turbine exhaust section; and afluid supply system coupled to the exhaust section, wherein the fluidsupply system is configured to route a cooling gas to the cooling gaspassage in the exhaust section, wherein the cooling gas has atemperature lower than the exhaust gas, wherein the cooling gascomprises an extracted exhaust gas, a gas separated from the extractedexhaust gas, carbon dioxide, carbon monoxide, nitrogen oxides, or acombination thereof. 23.-25. (canceled)
 26. The system of claim 22,wherein the cooling gas passage is isolated from the exhaust passage.27.-31. (canceled)
 32. The system of claim 22, wherein the fluid supplysystem comprises a temperature control system, a pressure controlsystem, a moisture removal system, a particulate removal system, or anycombination thereof.
 33. The system of claim 22, wherein the turbineexhaust section comprises a manway configured to provide access to aninterior of the turbine exhaust section, and wherein the manwaycomprises a seal configured to contain a flow of the cooling gas withinthe manway.
 34. The system of claim 22, wherein the turbine exhaustsection comprises a vent configured to withdraw the cooling gas from theturbine exhaust section. 35.-42. (canceled)
 43. A method, comprising:combusting a fuel with an oxidant and an exhaust gas in a combustionportion of a turbine combustor to generate combustion products; drivinga turbine with the combustion products from the turbine combustor;expanding and cooling the combustion products from the turbine throughan exhaust passage in an exhaust section; and routing a cooling gas froma fluid supply system to the exhaust section, wherein the cooling gascomprises an extracted exhaust gas, a gas separated from the extractedexhaust gas, carbon dioxide, carbon monoxide, nitrogen oxides, or acombination thereof.
 44. The method of claim 43, comprising routing thecooling gas from the fluid supply system to an outer shroud cavity ofthe exhaust section, wherein the outer shroud cavity is disposed betweenan outer shroud and a casing of the exhaust section, and the outershroud extends circumferentially about the exhaust passage.
 45. Themethod of claim 43, comprising routing the cooling gas from the fluidsupply system to an internal vane cavity of a vane, wherein the vaneextends into the exhaust passage of the exhaust section.
 46. The methodof claim 43, comprising routing the cooling gas from the fluid supplysystem to an inner shroud cavity of the exhaust section, wherein aninner shroud extends circumferentially about the inner shroud cavity,and the exhaust passage extends circumferentially about the innershroud.
 47. The method of claim 43, comprising routing the cooling gasthrough a bearing cavity of the exhaust section, wherein the bearingcavity comprises a bearing assembly.
 48. (canceled)
 49. (canceled) 50.The method of claim 43, comprising sealing a flow of the cooling gaswithin a manway of the exhaust section.
 51. The method of claim 43,comprising venting the cooling gas from the turbine exhaust sectionafter circulating the cooling gas through at least one cavity.